ABERDEEN Drilling Schools - Well Control.pdf

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ABERDEEN DRILLING SCHOOLS

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WELL CONTROL for the Rig-Site Drilling Team 1982 - 2002

➞

TRAINING MANUAL 2002 REVISED EDITION

ABERDEEN DRILLING SCHOOLS & Well Control Training Centre

WELL CONTROL for the Rig-Site Drilling Team

Training Manual 50 Union Glen, Aberdeen, AB11 6ER SCOTLAND U.K. Tel: (01224) 572709 Fax: (01224) 582896 e-Mail: [email protected]

V4 Rev March 2002


COPYRIGHT STATEMENT

All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, including photocopying and recording without the written permission of the copyright holder, application for which should be addressed to: Aberdeen Drilling Schools Ltd., 50 Union Glen, Aberdeen, AB11 6ER. Such written permission must also be obtained before any part of this publication is stored in a retrieval system of any nature. Brand names, company names, trademarks, or other identifying symbols appearing in illustrations and/or text are used for educational purposes only and do not constitute an endorsement by the author or publisher. Illustrations have been included in this document with the kind permission of Cooper Cameron UK Ltd, Shaffer A Varco Co and Hydril UK Ltd.

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CONTENTS

SECTION

Introduction 11

Fundamental Principles of Well Control

22

Causes of Kicks

33

Kick Indicators

44

Shut-in Procedures

55

Methods of Well Control

66

Well Control Equipment

7

Inspection, Testing and Sealing Components

89

Surface BOP Control Systems

910

Subsea BOP Control Systems and Marine Riser Systems

10

Formulae, Conversion Factors & Glossary of Terms

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WELL CONTROL for the Rig-Site Drilling Team INTRODUCTION

INTRODUCTION The objective of this manual is to provide a good understanding of the fundamentals of Well Control that can be applied to most Well Control operations. In all cases, minimising the kick volume and closing the well in is our first priority. We have tried, as far as possible, to avoid using specialist terms and iconography. This manual describes industry recognised standards and practices and basic Well Control procedures. They differ from our advanced Well Control methods which tend to be well, formation, or rig specific. The manual covers the guidelines found in API 16E, API 53 and API 59 along with the International Well Control Forum syllabus. It also covers the basic requirements for IADC WellCap Certification at all levels. All Well Control principles rely upon an understanding that good planning and early recognition and close in, is the best form of Well Control. Not all kicks are swabbed kicks, many wells are drilled into unknown formation. It is recognised that equipment can fail despite all the correct procedures being followed. This is why you will find the equipment section comprehensive and useful for general trouble shooting ideas.

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SECTION 1 :

FUNDAMENTAL PRINCIPLES OF WELL CONTROL Page

1. 0

Objectives

1

1. 1

General Information

1

1. 2

Hydrostatic Pressure

3

1. 3

Formation Pressure

4

1. 4

Normal Formation Pressure

4

1. 5

Abnormal Pressure

7

1. 6

Formation Fracture Pressure

12

1. 7

Leak-off Tests

14

1. 8

Maximum Allowable Annular Surface Pressure - MAASP

21

1. 9

Casing Setting Depths

21

1. 10

Circulating Pump Pressure

23

1. 11

Choke Line Friction

25

1.12

Workshop 1

30

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WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL

FUNDAMENTAL PRINCIPLES OF WELL CONTROL 1.0 OBJECTIVES The objectives of this section are to introduce the Fundamental Principles of Well Control.

1.1 GENERAL INFORMATION The function of Well Control can be conveniently subdivided into three main categories, namely PRIMARY WELL CONTROL, SECONDARY WELL CONTROL and TERTIARY WELL CONTROL. These categories are briefly described in the following paragraphs. Primary Well Control It is the name given to the process which maintains a hydrostatic pressure in the wellbore greater than the pressure of the fluids in the formation being drilled, but less than formation fracture pressure. If hydrostatic pressure is less than formation pressure then formation fluids will enter the wellbore. If the hydrostatic pressure of the fluid in the wellbore exceeds the fracture pressure of the formation then the fluid in the well could be lost. In an extreme case of lost circulation the formation pressure may exceed hydrostatic pressure allowing formation fluids to enter into the well. An overbalance of hydrostatic pressure over formation pressure is maintained, this excess is generally referred to as a trip margin. Secondary Well Control If the pressure of the fluids in the wellbore ( i.e. mud) fail to prevent formation fluids entering the wellbore, the well will flow. This process is stopped using a “blow out preventer” to prevent the escape of wellbore fluids from the well. This is the initial stage of secondary well control. Containment of unwanted formation fluids.

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1-1


Tertiary Well Control Tertiary well control describes the third line of defence. Where the formation cannot be controlled by primary or secondary well control (hydrostatic and equipment). An underground blowout for example. However in well control it is not always used as a qualitative term. ‘Unusual well control operations’ listed below are considered under this term:a)

A kick is taken with the kick off bottom.

b)

The drill pipe plugs off during a kill operation.

c)

There is no pipe in the hole.

d)

Hole in drill string.

e)

Lost circulation.

f)

Excessive casing pressure.

g)

Plugged and stuck off bottom.

h)

Gas percolation without gas expansion.

We could also include operations like stripping or snubbing in the hole, or drilling relief wells. The point to remember is "what is the well status at shut in?" This determines the method of well control.

1-2

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1.2 HYDROSTATIC PRESSURE Hydrostatic pressure is defined as the pressure due to the unit weight and vertical height of a column of fluid. Hydrostatic Pressure = Fluid Density x True Vertical Depth It is the vertical height/depth of the fluid column that matters, its shape is unimportant.

TVD

Note:

Figure 1.1 Different shaped vessels Since the pressure is measured in psi and depth is measured in feet, it is convenient to convert mud weights from pounds per gallon ppg to a pressure gradient psi/ft. The conversion factor is 0.052. Pressure Gradient psi/ft = Fluid Density in ppg X 0.052 Hydrostatic Pressure psi = Density in ppg X 0.052 X True Vert. Depth The Conversion factor 0.052 psi/ft per lb/gal is derived as follows: A cubic foot contains 7.48 US gallons. A fluid weighing 1 ppg is therefore equivalent to 7.48 lbs/cu.ft The pressure exerted by one foot of that fluid over the area of the base would be: 7.48 lbs –––––––– = 144 sq.ins

0.052 psi 12"

12"

Figure 1.2 Area definition of a cubic foot V4 Rev March 2002

12" 1-3


Example: The Pressure Gradient of a 10 ppg mud =

10 x 0.052

=

0.52 psi/ft

Conversion constants for other mud weight units are: Specific Gravity x 0.433

=

Pressure Gradient psi/ft

Pounds per Cubic Foot ÷ 144 =


1.3 FORMATION PRESSURE Formation pressure or pore pressure is said to be normal when it is caused solely by the hydrostatic head of the subsurface water contained in the formations and there is pore to pore pressure communication with the atmosphere. Dividing this pressure by the true vertical depth gives an average pressure gradient of the formation fluid, normally between 0.433 psi/ft and 0.465 psi/ft. The North Sea area pore pressure averages 0.452 psi/ft. In the absence of accurate data, 0.465 psi/ft which is the average pore pressure gradient in the Gulf of Mexico is often taken to be the “normal” pressure gradient. Note:

The point at which atmospheric contact is established may not necessarily be at sea-level or rig site level.

1.4 NORMAL FORMATION PRESSURE 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 subspace formations in that area. 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.

1-4

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For example, formation water with a salinity of 80,000 ppm sodium chloride (common salt) at a temperature of 25°C, has a pressure gradient of 0.465 psi/ft. Fresh water (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 (0.44 psi/ft) to saturated saline (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.

Figure 1.3 Average Normal Formation Pressure Gradients Pressure psi/ft

Gradient (SG)

Fresh water

0.433

1.00

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 area of Gulf of Mexico

Formation Water

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Example area Rocky Mountains and Midcontinent, USA

1-5


Figure 1.4

Porosity % 0

10

20

30

40

50

60

70

80

0

1000

Depth (metres)

2000

Permian Pennsylvania and Oklahoma (Athy) Lias Germany (Won Engelwardt)

3000

Miocene and Pliocene Po Valley (Storer) Tertiary Gulf Coast (Dickinson)

4000

Tertiary Japan (Magara) Joides

5000

Reduction in clay porosity as a function of depth (modified from Magara, 1978)

1-6

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1.5 ABNORMAL PRESSURE Every pressure which does not conform with the definition given for normal pressure is abnormal. The principal causes of abnormal pressures are:1.5.1 Under-compaction in shales When first deposited, shale has a high porosity. More than 50% of the total volume of uncompacted clay-mud may consist of water in which it is laid. During normal compaction, a gradual reduction in porosity accompanied by a loss of formation water occur as the thickness and weight of the overlaying sediments increase. Compaction reduces the pore space in shale, as compaction continues water is squeezed out. As a result, water must be removed from the shale before further compaction can occur. See Fig 1.4. Not all of the expelled liquid is water, hydrocarbons may also be flushed from the shale. If the balance between the rate of compaction and fluid expulsion is disrupted such that fluid removal is impeded then fluid pressures within the shale will increase. The inability of shale to expel water at a sufficient rate results in a much higher porosity than expected for the depth of shale burial in that area. Figure 1.5a

Quality of reservoir permeability.

Coarse-grained, well sorted Good permeability

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Fine Grained

Poorly-sorted

Poor permeability

1-7


Figure 1.5b 10000 8000 6000 4000

PERMEABILITY (md)

2000 1000 800 600 400 200 100 80 60 40 20

Coarse - and very coarse - grained Coarse - and medium - grained

10 8 6 4

Fine - grained Silty Clayey

2 1

0

2

4

6

8

10

12

14

16

18

20

22

24

26

28

30

32

34

36

POROSITY % The relationship between permeability and porosity (from Chilingar, 1964)

Figure 1.5c WATER ESCAPE CURVE

WATER CONTENT OF SHALES

(SCHEMATIC) WATER AVAILABLE FOR MIGRATION

% WATER 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

INTERLAYER WATER

LATTICE WATER STABILITY ZONE

2nd DEHYD'N STAGE

INTERLAYER WATER ISOPLETH

3rd DEHYDRATION STAGE

DEEP BURIAL WATER LOSS 'NO MIGRATION LEVEL'

Water Distribution Curves for Shale Dehydration

1-8

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1.5.2 Salt Beds Continuous salt depositions over large areas can cause abnormal pressures. Salt is totally impermeable to fluids and behave plastically. It deforms and flows by recrystallisation. Its properties of pressure transmission are more like fluids than solids, thereby exerting pressures equal to the overburden load in all directions. The fluids in the underlying formations cannot escape as there is no communication to the surface and thus the formations become over pressured. 1.5.3 Mineralisation The alteration of sediments and their constituent minerals can result in variations of the total volume of the minerals present. An increase in the volume of these solids will result in an increased fluid pressure. An example of this occurs when anhydrite is laid down. If it later takes on water crystallisation, its structure changes to become gypsum, with a volume increase of around 35%. 1.5.4 Tectonic Causes Is a compacting force that is applied horizontally in subsurface formations. In normal pressure environments water is expelled from clays as they are being compacted with increasing overburden pressures. If however an additional horizontal compacting force squeezes the clays laterally and if fluids are not able to escape at a rate equal to the reduction in pore volume the result will be an increase in pore pressure. Figure 1.6

EXTENSION

EXTENSION

COMPRESSION

COMPRESSION

COMPRESSION

COMPRESSION

Amount of Shortening

POSSIBLE OVERPRESSURED ZONES

Abnormal Formation Pressures caused by Tectonic Compressional Folding V4 Rev March 2002

1-9


1.5.5 Faulting Faults may cause abnormally high pressures. Formation slippage may bring a permeable formation laterally against an impermeable formation preventing the flow of fluids. Nonsealing faults may allow fluids to move from a deeper permeable formation to a shallower formation. If the shallower formation is sealed then it will be pressurised from the deeper zone. Figure 1.7 1.5.6 Diapirism

IMPERVIOUS SHALE

GAS OIL

WATER

This is a trap resulting from faulting in which the block on the right has moved up with respect to the one on the left.

A salt diapirism is an upward intrusion of salt to form a salt dome. This upthrust disturbs the normal layering of sediments and over pressures can occur due to the folding and faulting of the intruded formations.

Cap Rock Gas Oil Water

Water

Salt

Figure 1.8

Salt domes often deform overlying rocks to form traps like the one shown here.

1.5.7 Reservoir Structure Abnormally high pressures can develop in normally compacted rocks. In a reservoir in which a high relief structure contains oil or gas, an abnormally high pressure gradient as measured relative to surface will exist as shown in the following fig: a OIL

Gas-Oil Contact (GOC)

Gas Closure

Oil

Oil-Water Contact (OWC)

Water Spill Point

b Gas Water

Figure 1.9a

WATER

An anticlinal type of folded structure is shown here. Anticline differs from a dome in being long and narrow.

1 - 10

Figure1.9b

Gas-Water Contact (GWC)

Gas-Oil Contact (GOC)

Gas Oil

Trap nomenclature (a) in a simple structural trap and (b) in stratigraphic traps. Note that the size of the stratigraphic trap on the left is limited only by its petroleum content, while the size of the trap on the right is self-limiting.

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1.5.8 Typical types of hydrocarbon traps versus percentage of world total. Major types of oil traps and percentage of world’s petroleum occurrence for each. 75%

1%

Anticlines

Faults

2%

Salt Diapirs

3%

Unconformity

Structural Traps

7%

9%

Other Stratigraphic

Combination

3%

Reef

Stratigraphic Traps

Combination Traps

Figure 1.10 1.5.9 Typical hydrocarbon seals versus percentage of world total

Types of seals and percentage of world’s petroleum occurrence for each. 65% 33% 2%

Shale

Evaporite (salt)

Carbonate (limestone & dolomite)

Figure 1.11

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1 - 11


1.6 FORMATION FRACTURE PRESSURE In order to plan to drill a well safely it is necessary to have some knowledge of the fracture pressures of the formation to be encountered. The maximum volume of any uncontrolled influx to the wellbore depends on the fracture pressure of the exposed formations. If wellbore pressures were to equal or exceed this fracture pressure, the formation would break down as fracture was initiated, followed by loss of mud, loss of hydrostatic pressure and loss of primary control. Fracture pressures are related to the weight of the formation matrix (Rock) and the fluids (water/oil) occupying the pore space within the matrix, above the zone of interest. These two factors combine to produce what is known as the overburden pressure. Assuming the average density of a thick sedimentary sequence to be the equivalent of 19.2 ppg then the overburden gradient is given by: 0.052 x 19.2 = 1.0 psi/ft Since the degree of compaction of sediments is known to vary with depth the gradient is not constant. NORMAL COMPACTION Abnormally High Pressure Due to Hydrocarbon Column 0

1. Pressure on the Gas-Water Contact

= 2790 psi

2. Less Gas Column Pressure = 0.10 x 1000’ = 100 psi

1

3. Pressure at top of Sand = 2690 psi 4. Abnormal Gradient at top Sand 2690 psi ––––––– = 0.538 psi/ft 5000 ft

4

DEPTH - 1000 ft

5 1000’

GAS GRADIENT = 0.10 psi/ft

6

WATER

Normal pressure at the Gas-Water contact .465 x 6000’ = 2790 psi

7

8

9

Figure 1.12

1 - 12

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Onshore, since the sediments tend to be more compacted, the overburden gradient can be taken as being close to 1.0 psi/ft. Offshore, however the overburden gradients at shallow depths will be much less than 1.0 psi/ft due to the effect of the depth of seawater and large thicknesses of unconsolidated sediment. This makes surface casing seats in offshore wells much more vulnerable to break down and is the reason why shallow gas kicks should never be shut in. See Fig 1.13

Fracture Gradient Comparisons (for illustration purposes only)

A

B

0 ft Hydrostatic due to sea water 1500 x 0.445 = 667.5 psi

1500 ft Pressure due to overburden 3000 x 1.0 = 3000 psi Pressure due to overburden 1500 x 1.0 = 1500 psi

3000 ft Total Overburden 2167.5 psi (0.723 psi/ft)

Total Overburden 3000 psi (1.0 psi/ft)

C

D 0 ft

Hydrostatic due to sea water 1500 x 0.445 = 667.5 psi

1500 ft

Pressure due to overburden 12000 x 1.0 = 12000 psi Pressure due to overburden 10500 x 1.0 = 10500 psi

12000 ft Total Overburden 11167.5 psi (0.93 psi/ft)

Total Overburden 12000 psi (1.0 psi/ft)

Figure 1.13

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1 - 13


1.7 LEAK-OFF TESTS The leak-off test establishes a practical value for the input into fracture pressure predictions and indicates the limit of the amount of pressure that can be applied to the wellbore over the next section of hole drilled. It provides the basic data needed for further fracture calculations and it also tests the effectiveness of the cement job. The test is performed by applying an incremental pressure from the surface to the closed wellbore/casing system until it can be seen that fluid is being injected into the formation. Leak-off tests should normally be taken to this leak-off pressure unless it exceeds the pressure to which the casing was tested. In some instances as when drilling development wells this might not be necessary and a formation competency test, where the pressure is only increased to a predetermined limit, might be all that is required. 1.7.1 Leak-Off Test Procedure: Before starting, gauges should be checked for accuracy. The upper pressure limit should be determined.

1 - 14

1)

The casing should be tested prior to drilling out the shoe.

2)

Drill out the shoe and cement, exposing 5 - 10 ft of new formation.

3)

Circulate and condition the mud, check mud density in and out.

4)

Pull the bit inside the casing. Line up cement pump and flush all lines to be used for the test.

5)

Close BOPs.

6)

With the well closed in, the cement pump is used to pump a small volume at a time into the well typically a 1/4 or 1/2 bbl per min. Monitor the pressure build up and accurately record the volume of mud pumped. Plot pressure versus volume of mud pumped.

7)

Stop the pump when any deviation from linearity is noticed between pump pressure and volume pumped.

8)

Bleed off the pressure and establish the amounts of mud, if any, lost to the formation.

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EXAMPLES OF LEAK-OFF TEST PLOT INTERPRETATION In non-consolidated or highly permeable formations fluid can be lost at very low pressures. In this case the pressure will fall once the pump has been stopped and a plot such as that shown in Fig 1.14a will be obtained. Figs 1.14b and 1.14c show typical plots for consolidated permeable and consolidated impermeable formations respectively. b) Consolidated Permeable Formations

PRESSURE

PRESSURE

a) Unconsolidated Formations

CUMULATIVE VOLUME

CUMULATIVE VOLUME

c) Consolidated Impermeable Formations

Final Pumping Pressure After Each Volume Increment

PRESSURE

Final Static Pressure After Each Volume Increment Leak-off Point

CUMULATIVE VOLUME

IDEALISED LEAK-OFF TEST CURVES Figure 1.14 V4 Rev March 2002

1 - 15


Working example of leak-off test procedure (floating rigs) “Operational Drilling Procedures for Floating Rigs” is designed to determine the equivalent mud weight at which the formation will accept fluid. This test is not designed to break down or fracture the formation. This test is normally performed at each casing shoe. Prior to the formation leak-off, have “handy” a piece of graph paper (see graph 1 ), pencil and straight edge (ruler). Utilising the high pressure cement pumping unit, perform leak-off as follows:

1 - 16

1.

Upon drilling float equipment, clean out rat hole and drill 15 ft of new hole. Circulate and condition hole clean. Be assured mud weight in and mud weight out balance for most accurate results.

2.

Pull bit up to just above casing shoe. Install circulating head on DP.

3.

Rig up cement unit and fill lines with mud. Test lines to 2500 psi. Break circulation with cementing unit, be assured bit nozzles are clear. Stop pumping when circulation established.

4.

Close pipe rams. Position and set motion compensator, overpull drillpipe (+/- 10,000 lbs), close choke/kill valves.

5.

At a slow rate (i.e. 1/4 or 1/2 BPM), pump mud down DP.

6.

a.

Pump 1/4 bbl - record/plot pressure on graph paper.

b.


c.


d.


e.


f.

Continue this slow pumping. Record pressure at 1/4 bbl increments until two points past leak-off. (See examples, Graph 1, 2 & 3.)

g.

Upon two points above leak-off, stop pumping. Allow pressure to stabilize. Record this stabilized standing pressure (normally will stabilize after 15 mins or so).

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h.

Bleed back pressure into cement unit tanks. Record volume of bleed back.

i.

Set and position motion compensator, open rams.

j.

Rig down and cement unit lines. Proceed with drilling operations.

k.

Leak-off can be repeated after step 6 if data confirmation is required, otherwise leak-off test is complete.

NOTE: For 20" and 13 3/8" csg leak-off tests, plot pressure every 1/2 bbl. Results will be the same. It should be noted that in order to obtain the proper leak-off and pumping rate plot, it will be necessary to establish a continuous pump rate at a slow rate in order to allow time to read the pressure and plot the point on the graph. (Barrels pumped vs. pressure - psi), normally 1/2 BPM is sufficient time. A pressure gauge of 0-2000 psi with 20 or 25 increments is recommended. NOTE: In the event Standing Pressure is lower than leak-off point. Use standing pressure to calculate equivalent mud weight. Always note volume of mud bled back into tanks.

1.7.2 Formation Breakdown Pressure (psi) = hydrostatic pressure of mud in casing + applied surface pressure = (mud wt. x constant x vert shoe depth) + surface pressure The formation breakdown pressure can be expressed as a GRADIENT. Formation Breakdown Pressure (psi) Formation Breakdown Gradient (psi/ft) = –––––––––––––––––––––––––––––– Vert. Shoe Depth (ft) The formation breakdown gradient expressed as a maximum allowable mud weight: Maximum Allowable Mud Weight (ppg) = Formation Breakdown Gradient (psi/ft) ÷ 0.052 or Formation Breakdown Pressure (psi) Maximum Allowable Mud Weight (ppg) = –––––––––––––––––––––––––––––– ÷ 0.052 Vert Shoe Depth (ft)

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1 - 17


Graph 1.1 Formation Pressure Test Work Sheet

1100

1000

900

SURFACE TEST PRESSURE - PSI

800

700

600

500

400

300

NOTE: Commence measuring volume NOTE: after pressuring up to 200 psi NOTE: Pump at a 0.3 BPM rate and NOTE: plot pressures and volumes NOTE: (BBL's MUD)

200

100

0 0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

BARRELS MUD PUMPED

1 - 18

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Graph 1.2

Typical Pressure Test csg set at 5000' TVD w/12 lb mud in hole.

1100

Required Test Pressure (Equivalent to 16,0 Mud)

1000

900

705 psi 5 min stabilized pressure


800

700

600

500

400

300

NOTE: Commence plotting pressure NOTE: and pumped volume after NOTE: pressuring up to 200 psi

200

100

0 0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

BARRELS MUD PUMPED

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1 - 19


Graph 1.3 Typical Pressure Plot for Formation Breakdown and Fracture Propagation

Formation Breakdown Pressure

1100

Leak-off Pressure

1000

900


800

700

600

500

400

300

NOTE: Commence plotting pressure NOTE: and pumped volume after NOTE: pressuring up to 200 psi

200

100

0 0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

BARRELS MUD PUMPED

1 - 20

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SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL

1.8 MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE - MAASP.

The leak-off test was used to determine the strength of the formations below the casing shoe.

The Formation Breakdown Pressure = an applied surface pressure + hydrostatic pressure of mud in the casing

The applied surface pressure at which leak-off occurred is the maximum allowable annular surface pressure with the mud weight in use at that time. MAASP is the maximum surface pressure that can be tolerated before the formation at the shoe fractures. MAASP = Formation Breakdown pressure at shoe – Hydrostatic Pressure of mud in use in the casing shoe or rewritten as:

MAASP = (Fracture gradient – Mud gradient) x True Vert. Shoe Depth

or as:

MAASP = (Max equiv. mud wt. – Mud wt. in casing) x (0.052 x True Vert. shoe depth)

MAASP is only valid if the casing is full of the original mud, if the mud weight in the casing is changed MAASP must be recalculated. The calculated MAASP is no longer valid if influx fluids enter into the casing.

Seabed

1.9 CASING SETTING DEPTHS

The choice of setting depths for all the casing strings is a vital part of the well planning process. An incorrect decision with the casing setting depths too shallow could have serious consequences. An unnecessarily deep setting depth could have adverse economic consequences when considering the extra time needed to drill the hole deeper and the extra amount of casing required to be run and cemented.

30" Casing (Conductor)

36" Hole

20" Casing (Surface String.)

26" Hole

13 1/8" Casing (Intermediate String)

17 1/2" Hole

9 5/8" Casing (Production String)

12 1/4" Hole

Figure 1.15 Typical Offshore Casing Program

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7" Liner

8 1/2" Hole

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SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL

1.9.1 Deep Casing Setting Depths

The selection of deeper casing setting depths will use different criteria to those used for shallow casing seats. Initial selection of the setting depth is made with reference to the anticipated lithological column, formation pressure and fracture gradient profiles. Once all the information has been collated from offset well data a plot similar to that shown in Fig 1.16 can be drawn up. By studying the geology and pressure profiles, tentative setting depths can be chosen based on the prevention of formation breakdown by mud weights in use in the subsequent hole section. See Fig 1.17. From a Well Control point of view, it is necessary to determine whether this tentative setting depth will give adequate protection against formation breakdown when a kick is taken. A kick tolerance “factor” will normally be applied. Preferred Setting Depths

Required Setting Depths

(based on lithological column) (to prevent formation fracture due to weight of mud column)

0

2

0

Fracture Gradient

2

Fracture Gradient

6

8

10

4

Depth x 1000 ft

Depth x 1000 ft

4

6

10

Pore Pressure Gradient

Pore Pressure Gradient

12

14

12

14

8.0

10.0

12.0

14.0

16.0

18.0

Pressure Gradient - lb/gal Equivalent

PRESSURE PROFILE PREDICTIONS

Figure 1.16

1 - 22

Proposed Mud Weight program

8

20.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

Pressure Gradient - lb/gal Equivalent

PRESSURE PROFILES WITH CASING SETTING DEPTHS

Figure 1.17

V4 Rev March 2002


1.10 CIRCULATING PUMP PRESSURE The pressure provided by the rig pump is the sum of all of the individual pressures in the circulating systems. All the pressure produced by the pump is expended in this process, overcoming friction losses between the mud and whatever it is in contact with: • • • •

Pressure loss in surface lines Pressure loss in drill-string Pressure loss across but jets Pressure loss in annulus

Pressure losses are independent of hydrostatic and imposed pressures. Pressure losses in the annulus acts as a “back pressure” on the exposed formations, consequently the total pressure at the bottom of the annulus is higher with the pump on than with the pump off. Circulating bottom hole pressure

=

Static bottom hole pressure +

STATIC Formation will Kick

Annulus pressure losses

CIRCULATING Formation under Control

0 psi

3000 psi

Annulus Pressure Loss = 250 psi 10 ppg MUD

BHP = 5200 psi

BHP = 5450 psi 10000’

5300 psi

V4 Rev March 2002

Formation Pressure Figure 1.18

5300 psi

1 - 23


The total pressure on bottom can be calculated and converted to an equivalent static mud weight which exerts the same pressure. Equivalent Mud Wt (ppg) = (APL + Pmud ) ÷ 0.052 ÷ TVD a or APL Equivalent Mud wt E.C.D = Mud Wt in use + –––––––––– 0.052 X TVD Where:

APL Pmud

a

= =

Annulus Pressure Loss Hydrostatic Mud Pressure in Annulus

Circulating pressure will be affected if the pump rate or the properties of the fluid being circulated are changed. Example:Assuming a circulating pump pressure is 3000 psi when pumping at 100 spm. The pump speed is increased to 120 spm. To approximate the new circulating pump pressure: P(2) = P(1) x Where:-

(

New Pump Speed 2 ––––––––––––––––– Original Pump Speed

)

P(1) = Original pump pressure at original pump speed. P(2) = New circulating pressure at new pump speed.

P(2) = 3000 x

( )

120 2 –––– 100

P(2) = 4320 psi at 120 spm

Example:Assuming a circulating pump pressure in 3000 psi with a 10 ppg mud weight pumping at 100 spm. If the mud weight in the system was changed to 12 ppg. To approximate the new circulating pump pressure: P(2) = P(1) x

New Mud Weight –––––––––––––––– Original Mud Weight

12 P(2) = 3000 x ––– 10

P(2) = 3600 psi when circulating with 12 ppg mud. Note:

1 - 24

Changing either pump speed or mud weight will affect annulus pressure losses.

V4 Rev March 2002


1.11 CHOKE LINE FRICTION LOSSES IN SUBSEA KILL OPERATIONS Figure 1.19 In subsea situations, a pressure loss exists when circulating through the choke due to the friction losses in the extended choke line running up from the BOP. This pressure loss is not accounted for in normal Slow Circulating Rate (SCR) measurements, which are taken while circulating up the marine riser (see Fig 1.19).

500 PSI

SHAKERS

If the normal method of bringing pumps to kill speed is followed (that is, choke manifold pressure maintained equal to SICP until kill rate is achieved), bottom hole pressure will be increased by an amount equal to this choke line friction loss (CLFL). This excess pressure can result in serious lost circulation problems during the kill operations. Since fracture gradients generally decrease with increased water depth, correct handling of the CLFL becomes more critical as water depth increases. Beyond approximately 500 feet water depth, it should always be considered while planning well control operations. It is possible to measure CLFL while taking SCR’s. One simple way to do this is to pump down the choke line at reduced pump rates (taking returns up the open marine riser as is shown in Figure 1.20) and record the pressure reading on the choke manifold gauge.

CONVENTIONAL SCF FLOW PATH

Figure 1.20 DRILL PIPE

CHOKE MANIFOLD

0 PSI

200 PSI CHOKE

SHAKERS

FROM PUMP

It is fundamental to all standard methods of well control to maintain constant bottom hole pressure (BHP) throughout kill operations. To accomplish this a method must be used to keep total applied casing pressures relatively constant while bringing the mud pump to kill rate. In the absence of significant CLFL (surface stacks or shallow water), the method used is to merely keep choke manifold pressure equal to SICP until the pump is up to speed. CLFL MEASUREMENT PUMPING DOWN CHOKE LINE CLCF = 200 PSI

V4 Rev March 2002

1 - 25


But when CLFL exists, total applied casing pressure varies from SICP at pump start-up to SICP + CLFL with the pump at kill rate, if the above method were used. This would cause bottom hole pressure to increase by an amount equal to CLFL, as shown in Figures 1.21 and 1.22 Figure 1.21

Figure 1.22

DRILL PIPE

CHOKE MANIFOLD

DRILL PIPE

CHOKE MANIFOLD

800 PSI

1000 PSI

1500 PSI

1000 PSI CHOKE

CHOKE

RETURNS

CLFL 0 PSI (STATIC) SUBSEA BOP

SUBSEA BOP

APL 0 PSI

BHP 6000 PSI

Pf = 6000 psi Ph = 5200 psi (in annulus) PUMPS OFF (kick shut in)

1 - 26

CLFL 200 PSI (DYNAMIC)

APL NEGLIGIBLE

BHP 6200 PSI

Pf = 6000 psi Ph = 5200 psi (in annulus) PUMP AT KILL RATE HOLDING CONSTANT CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 200 psi increase

V4 Rev March 2002


Figure 1.23 To eliminate this problem, two methods exist. First, by reducing choke manifold pressure by an amount equal to a known CLFL (adjusting choke manifold pressure to SICP -CLFL), the effect of the CLFL is negated. This is accomplished by reducing the original SICP by the amount of CLFL while bringing the pumps to speed (see Figure 1.23). Once kill rate pressure has been established, the choke operator switches over to the drill pipe gauge and follows the drill pipe pressure graph in the usual way. Or secondly, given a choke manifold configuration with separate pressure gauges for choke and kill lines, it is possible to utilise the kill line (shut off down-stream of the gauge outlet to prevent flow, thus eliminating friction) as a pressure connection to a point upstream of any potential CLFL (known or unknown). This is shown in Figure 1.24. If the kill line gauge in this instance is kept constant while bringing the pump to speed, the effect of CLFL is eliminated.

DRILL PIPE

CHOKE MANIFOLD

1300 PSI

800 PSI CHOKE

RETURNS CLFL 200 PSI (DYNAMIC)

SUBSEA BOP

APL NEGLIGIBLE

BHP 6000 PSI

Pf = 6000 psi Ph = 5200 psi (in annulus) PUMP AT KILL RATE WITH REDUCED CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 0 psi increase

Figure 1.24 Note the advantages of the second method: 1.

The gauge reading choke manifold pressure will show a decrease after pump is up to speed. The amount of this decrease is equal to the CLFL.

2.

No precalculated or pre-measured CLFL information is required.

3.

The kill line gauge can be subsequently used like the choke manifold pressure gauge on a surface stack for the purposes of altering pump rates or problem analysis.

NOTE: If the second method of handling the CLFL situation is preferred, it would be advisable to rig a remote kill line pressure gauge which could be seen by the choke operator.

V4 Rev March 2002

1000 PSI

DRILL PIPE

CHOKE MANIFOLD

1300 PSI

800 PSI CHOKE

RETURNS KLFL 0 PSI (STATIC)

SUBSEA BOP


APL NEGLIGIBLE

BHP 6000 PSI

Well shut in Pf = 6000 psi Ph = 5200 psi (in annulus) PUMP AT KILL RATE HOLDING CONSTANT KILL LINE PRESSURE READING CHANGE IN BHP = 0 psi increase

1 - 27


It is extremely important to note that regardless of which method is used, they both accomplish the goal of maintaining constant bottom hole pressure equal to formation pressure, just as would be the case were CLFL absent. This is done without the need to alter any calculations on the kick sheet. Thus initial and final circulating pressures, which are read on the drill pipe gauge, are unaffected by CLFL. CLFL is recorded on the Kick Sheet for convenience only – it is not used in kick sheet calculations. Several additional points should be made about CLFL. It should be noted that it will only be possible to use the above recommended methods when SICP is greater than CLFL. If this is not true, it will be unavoidable to apply excess pressure to the bottom of the hole using standard well control procedures. Also, as kill mud comes up the annulus, total applied casing pressure needed to maintain constant bottom hole pressure will eventually drop below CLFL. After this point, drill pipe pressures will exceed planned Final Circulating Pressure in spite of having the choke wide open with no choke manifold back pressure.

Figure 1.25 DRILL PIPE

CHOKE MANIFOLD

75 PSI

100 PSI CHOKE

SUBSEA BOP

CLFL 0 PSI (STATIC)

APL 0 PSI

BHP 5200 PSI

Pf = 5200 psi Ph = 5100 psi (in annulus) PUMPS OFF (kick shut in) FCP @ 4 bbl/min = 400 psi FCP @ 2 bbl/min = 200 psi CLFL @ 4 bbl/min = 200 psi CLFL @ 2 bbl/min = 60 psi

Figure 1.26 These situations can be mitigated by use of unusually slow pumping rates or by taking returns up choke and kill lines simultaneously. Figures 1.25 - 1.28 illustrate this problem and methods of dealing with it. They show an example in which a static SICP of 100 psi is reduced while pumping as result of the increase in back pressure created in circulating up the choke line, by itself or choke and kill lines together.

DRILL PIPE

CHOKE MANIFOLD

575 PSI

0 PSI CHOKE

RETURNS

SUBSEA BOP

a


APL NEGLIGIBLE

Fig 24: Pumping 4 bbl/min with choke wide open. Note increase in BHP due to excess CL friction.

1 - 28

BHP 5300 PSI

Pf = 5200 psi Ph = 5100 psi (in annulus) PUMP AT 4 BBL/MIN HOLDING 0 PSI CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 100 psi increase

V4 Rev March 2002


Fig 1.27: Pump rate reduced to bbl/min. BHP is held constant at SICP - CLFL

Fig 1.28: By taking flow up choke and kill lines simultaneously, the same effect is achieved as in fig 1.27, but at a pumping rate of 4 bbl/min.

Figure 1.27

Figure 1.28

DRILL PIPE

CHOKE MANIFOLD

275 PSI

40 PSI

CHOKE MANIFOLD

475 PSI

40 PSI

40 PSI

CHOKE

RETURNS

SUBSEA BOP

DRILL PIPE


CHOKE

CHOKE

RETURNS

RETURNS KLFL 60 PSI (DYNAMIC)

2 BBL/MIN

2 BBL/MIN

SUBSEA BOP


4 BBL/MIN

APL NEGLIGIBLE

BHP 5200 PSI

Pf = 5200 psi Ph = 5100 psi (in annulus) PUMP AT 2 BBL/MIN WITH REDUCED CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 0 psi increase

V4 Rev March 2002

APL NEGLIGIBLE

BHP 5200 PSI

Pf = 5200 psi Ph = 5100 psi (in annulus) PUMP AT 4 BBL/MIN USING CHOKE AND KILL LINES FOR RETURN FLOW CHANGE IN BHP = 0 psi

1 - 29


1.12 - WORKSHOP 1 SCORE 1.

Convert the following mud densities into pressure gradients. a. 13.5 ppg b. 16 ppg c. 12 ppg

2.

2

Convert the following gradients into mud densities. a. 0.806 psi/ft b. 0.598 psi/ft c. 0.494 psi/ft

3.

_____________ psi/ft _____________ psi/ft _____________ psi/ft

_____________ ppg _____________ ppg _____________ ppg

2

Calculate the hydrostatic pressure for the following. a. 9.5 ppg mud at 9000ft MD/8000 ft TVD =_____________ b. 15.5 ppg mud at 18000ft TVD/21000ft MD =_____________ c. 0.889 psi/ft mud at 11000ft MD/9000ft TVD =_____________

4.

Convert the following pressures into equivalent mud weights in PPG. a. 3495 psi at 7000ft b. at 4000ft with 2787 psi c. 12000ft MD/10500ft TVD with 9000 psi

5.

=_____________ =_____________ =_____________

2

High bottom hole temperatures could affect the hydrostatic pressure gradients resulting in: a. An increase in the hydrostatic gradient b. A decrease in the hydrostatic gradient c. Would have no effect

1 - 30

2

2

V4 Rev March 2002


SCORE 6.

Assuming a 10 ppg mud is being circulated at 700 GPM at a depth of 10000ft TVD/MD the circulating pump pressure is 3000 psi. If the circulating friction losses in the system are as follows: Pressure losses through pipe/collars Pressure loss across the bit jets Pressure loss in the annulus a.

1200 psi 1600 psi 200 psi

When circulating what is the dynamic bottom hole pressure? Answer.....................

b.

What is the static bottom hole pressure? Answer.....................

c.

2

Referring to the data given above, if the mud weight being circulated at 700 GPM was 12 ppg rather than 10 ppg, what would pump pressure be? Answer......................

7.

2

Will this increase in the pump speed have any effect on bottom hole pressure? Answer YES/NO

f.

2

If the pump speed is increased to give 800 GPM, what will the pump pressure be? Answer.....................

e.

2

What is the equivalent circulating density ECD? Answer.....................

d.

2

2

When circulating a 12 ppg mud at 10000ft ECD is 12.3 ppg. What is the annular pressure loss? Answer......................

V4 Rev March 2002

2

1 - 31


SCORE 8.

Calculate the pressure that one barrel of 12 ppg mud Wt exerts. a.

Around the drill collars if the annular capacity is 0.03 bbls/ft. Answer......................

b.

Around the drill pipe if the annular capacity is 0.05 bbls/ft. Answer......................

9.

2

Drilling at 12700ft with an 8 1/2" bit, the drill pipe is 5" with 700ft of 6 1/2" collars. The mud weight = 12 ppg. The yield point of the mud is 12lbs/100ft2. Use the equation given below to determine ECD. Answer...................... Annular-pressure loss =

where

12.

2

If a 12 ppg mud over-balances the formation pressure by 240 psi theoretically how far could the mud level fall before going under-balance? Answer.......................

11.

2

If the fluid level in a well bore fell by 480ft, what is the reduction in bottom hole pressure if the mud weight is 12 ppg? Answer......................

10.

2

YP L DH DP

= = = =

4

YP x L ————— 200(DH-DP) 2

Yield point of mud in lbs/100ft Length of annulus, collar or pipe Hole diameter Collar or pipe diameter

If a formation pore pressure gradient at 8500ft is 0.486 psi/ft, what mud weight is required to give an over-balance of 200 psi? Answer......................

2

WORKSHOP 1 - Answers 1 - 32

V4 Rev March 2002


WORKSHOP 1 - Answers 1.

MUD WEIGHT x 0.052 a. b. c.

2.

0.702 psi/ft 0.832 psi/ft 0.624 psi/ft

0.806 ÷ 0.052 0.598 ÷ 0.052 0.494 ÷ 0.052

= = =

15.5 ppg 11.5 ppg 9.5 ppg

T.V.D. x MUD WEIGHT x 0.052 a. b. c.

4.

= = =

GRADIENT ÷ 0.052 a. b. c.

3.

13.5 x 0.052 16.0 x 0.052 12.0 x 0.052

8000 x 9.5 x .052 18000 x 15.5 x .052 9000 x 0.889

= = =

3952 psi 14508 psi 8001 psi

= = =

9.6 ppg 13.39 ppg (13.4) 16.48 ppg (16.5)

PRESS ÷ T.V.D ÷ .052 a. b. c.

3495 ÷ 7000 ÷ .052 2787 ÷ 4000 ÷ .052 9000 ÷ 10500 ÷ .052

5.

b.

6.

(T.V.D. x MUD WT x .052) + A.P.L. a. b. c. d.

Note d.

V4 Rev March 2002

(10000ft x 10ppg x .052) + 200 10000 x 10 x .052 5400 ÷ 10000 ÷ .052 3000 x (800)2 —— (700)

= = = =

5400 psi 5200 psi 10.38 ppg 3918 psi

This calculation is the same relationship as Press-Strokes-Relationship. (i.e.) P x (new S.P.M)2 ————— (old S.P.M.)

1 - 33


e.

YES

f.

PRESS x (new MUD WT) ———————— (old MUD WT) 3000

7.

A.P.L.

A.P.L.

8.

1 - 34

x (12) —— (10) = = = =

=

3600 psi

(ECD - MUD WT) x (TVD x .052) (12.3 - 12) x (10000 x .052) .3 x 520 156 psi

MUD g psi/ft ——— ANN vol psi/ft a. =

12 x .052

=

b. =

.624 psi/bbl —————— .05

9.

480 x 12 .052

=

10.

PRESS - psi ——— MUD g psi/ft

=

.624 = —— .03

20.8 psi/bbl

= 12.48 Psi/bbl

299.52 psi (300 psi)

240 = —— .624ft

384ft

V4 Rev March 2002


11.

A.P.L. around D/C

=

12 x 700 = 21 psi ————— 200(8.5-6.5)

A.P.L. around D/P

=

12 x 12000 = 206 psi —————— 200 x (8.5 - 5)

TOTAL A.P.L.

12.

ECD

=

12

ECD

=

12.34 PPG

8500 x .486

+

= 227psi

227 —— ÷ .052 12700

= 4131 + 200 = 4331 psi

4331 ÷ 8500 ÷ .052 = 9.79 ppg = (9.8 ppg)

V4 Rev March 2002

1 - 35

SECTION 2 :

CAUSES OF KICKS Page

2. 0

Objectives

1

2. 1

Introduction

1

2. 2

Primary Well Control- How it is Affected

1

2. 3

Causes of Kicks and Influxes

6

2. 4

Hydrate Formation & Prevention

15

2. 5

Function of Drilling Muds

17

2. 6

Extracts From API RP59

24

2. 7

Workshop 2

31

V4 Rev March 2002

WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS

CAUSES OF KICKS 2.0 OBJECTIVES The objectives of this section are to Highlight the Causes of Kicks and Influxes.

2.1 INTRODUCTION Primary control is defined as using the drilling fluid to control formation fluid pressure. The drilling fluid has to have a density that will provide sufficient pressure to overbalance pore pressure. If this overbalance is lost, even temporarily then formation fluids can enter the wellbore. Preventing the loss of primary control is of the utmost importance. Definition of Kick A kick is an intrusion of unwanted fluids into the wellbore such that the effective hydrostatic pressure of the wellbore fluid is exceeded by the formation pressure. Definition of Influx An influx is an intrusion of formation fluids into the wellbore which does not immediately cause formation pressure to exceed the hydrostatic pressure of the fluid in the wellbore, but may do, if not immediately recognised as an influx, particularly if the formation fluid is gas.

2.2 PRIMARY WELL CONTROL - HOW IT IS EFFECTED To ensure primary well control is in place the following procedures and precautions must be observed. Mud Weight Mud into and out of the well must be weighted to ensure the correct weight is being maintained to control the well. This task is normally carried out by the shaker man at least every thirty minutes or less, depending upon the nature of the drilling operation and/or company policy. The mud weight can be increased by increasing the solid content and decreased either by dilution or the use of solids control equipment. Tripping Procedures Tripping in or out of the well must be maintained using an accurate log called a trip sheet. A trip sheet is used to record the volume of mud put into the well or displaced from the well when tripping. A calibrated trip tank is normally used for the accurate measurement of mud volumes and changes to mud volumes while tripping. V4 Rev March 2002

2-1


Figure 2.1 Well Name

Trip No.

Date

Mud Weight

Fluid Loss

Depth

D.P. Size

D.P. Displacement

Time Trip Started

D.C. Size

D.C. Displacement

Number of Stands

DISPLACEMENT Theoretical Last Trip Per ___ Std.

Total

Per ___ Std.

If rig pump is used, calculate from strokes.

2-2

Total

This Trip Per ___ Std.

Comments

Total

If trip tank is used, record level of decrease.

V4 Rev March 2002


When tripping pipe or drill collars out of the hole, a given volume of mud is put into the well for the volume of steel removed. If the volume required to fill the hole is significantly less than the volume of steel removed, then tripping must be stopped to ensure the well is stable, and consideration given to going back to bottom to condition the mud and investigate the cause of the problem. THE HOLE MUST BE KEPT FULL AT ALL TIMES A full opening or safety valve should be available at all times on the drill floor together with the required crossover subs. A non-return (i.e. grey) valve should also be readily available. Figure 2.3 Figure 2.2 NON RETURN SAFETY VALVE (GREY VALVE) FULL BORE OPENING SAFETY VALVE

RELEASE TOOL VALVE RELEASE ROD

Body

Upper Seat

Crank Ball VALVE SEAT

Lower Seat

VALVE SPRING

Trip Margin (Safety Factor) Trip Margin (Safety Factor) is an overbalance to compensate for the loss of ECD and to overcome the effects of swab pressures during a trip out of the hole.

V4 Rev March 2002

2-3


Flow Checks Flow checks are performed to ensure that the well is stable. Flow checks should be carried out with the pumps off to check the well with ECD effects removed. Flow checks are usually performed when a trip is going to take place at the following minimum places: •

on bottom

•

at the casing shoe

•

before the BHA is pulled into the BOP's

Short Trips/Wiper Trips In some circumstances prior to pulling out of the hole a short trip, 5 or 10 stands should be considered. The well is then circulated and mud returns carefully monitored. Pumping a Slug of Heavy Mud This is a practice often carried out to enable the pipe to be pulled dry and the hole to be more accurately monitored during the trip. The following equation is used to calculate the dry pipe volume for the slug pumped: Dry Pipe Volume = Slug Volume x (Slug Weight ÷ Mud Weight - 1) This dry pipe volume can be converted to Dry Pipe Length by dividing this volume by the internal capacity of the pipe as illustrated in the following equation: Dry Pipe Length = Dry Pipe Volume (bbls) ÷ Drill Pipe Capacity (bbls/ft) Mud Logging A logging unit if available is extremely important particularly with respect to well control. The unit carries out some of the following services:

2-4

•

Gas detection in the mud

•

Gas analysis

•

Cuttings density analysis

•

Recording mud densities in and out

•

Recording flow line temperatures

•

Recording penetration rates

•

Pore Pressure Trends V4 Rev March 2002


A typical mud logging system is illustrated in Figure 2.4 below. KELLY POSITION ROP WOB DEPTH KELLY HOSE SWIVEL

STAND PIPE STANDPIPE PRESSURE PUMP

KELLY

PUMP RATE

SUCTION SUCTION PIT FLOWLINE PIT LEVELS

SHALE SLIDE GAS QUANTITY GAS TYPE MUD TEMPERATURE RETURN MUD WEIGHT

P

R

O E CE V S A S LU IN A G T A IO N N D

CUTTINGS DENSITY

SHAKER

• ROTARY SPEED • TORQUE

G GIN G O DL MU UNIT VDU IN COMPANY REP'S OFFICE

V4 Rev March 2002

2-5


Communication If a transfer of mud to the active system is requested the driller will be informed, the logging unit must likewise be informed. Good communication all round is essential. Alarms The high and low settings for the pit level recorder and flow line recorder must be checked and are set to appropriate values.

2.3 CAUSES OF KICKS AND INFLUXES The most common causes of kicks are: •

Improper monitoring of pipe movement (drilling assembly and casing). -

Trip out - making sure hole takes the proper amount of mud. Trip in - making sure it gives up proper amount of mud and preventing lost circulation due to surges.

•

Swabbing during pipe movement.

•

Loss of circulation.

•

Insufficient mud weight. -

•

Abnormal pressured formations Shallow gas sands

Special situations. -

Drill stem testing Drilling into an adjacent well Excessive drilling rate through a gas sand

Surveys in the past have shown that the major portion of well control problems have occurred during trips. The potential exists for the reduction of bottom hole pressure due to:

2-6

•

Loss of ECD with pumps off.

•

Reduction in fluid levels when pulling pipe and not filling the hole.

•

Swabbing.

V4 Rev March 2002


2.3.1 FAILURE TO KEEP THE HOLE FULL DURING A TRIP If the fluid level in the hole falls as pipe is removed a reduction in bottom hole pressure will occur. If the magnitude of the reduction exceeds the trip margin or safety overbalance factor a kick may occur. The hole must be kept full with a lined up trip tank that can be monitored to ensure that the hole is taking the correct amount of mud. If the hole fails to take the correct mud volume, it can be detected. A trip tank line up is shown in Fig 2.5. BELL NIPPLE RETURN LINE

FLOAT

FILL UP LINE

TANK

INDICATOR PUMP

Figure 2.5

CONTINUOUS CIRCULATING TRIP TANK

It is of the utmost importance that drill crews properly monitor displacement and fill up volumes when tripping. The lack of this basic practice results in a large amount of well control incidents every year.

2.3.2 SWABBING AND SURGING Swabbing is when bottom hole pressure is reduced below formation pressure due to the effects of pulling the drill string, which allows an influx of formation fluids into the wellbore. When pulling the string there will always be some variation to bottom hole pressure. A pressure loss is caused by friction, the friction between the mud and the drill string being pulled. Swabbing can also be caused by the full gauge down hole tools (bits, stabilisers, reamers, core barrels, etc.) being balled up. This can create a piston like effect when they are pulled through mud. This type of swabbing can have drastic effects on bottom hole pressure. V4 Rev March 2002

2-7


The factors affecting swabbing and surging are: •

Pulling speed of pipe.

•

Mud properties.

•

Viscosity.

•

Hole geometry.

Surging Surging is when the bottom hole pressure is increased due to the effects of running the drill string too fast in the hole. Down hole mud losses may occur if care is not taken and fracture pressure is exceeded while RIH. Proper monitoring of the displacement volume with the trip tank is required at all times. Figure 2.6

PRESSURE SURGES SWABBING ACTION Swabbing is a recognised hazard whether it is “low" volume swabbing or “high” volume swabbing. A small influx volume may be swabbed into the open hole section. The net decrease in hydrostatics due to this low density fluid will also be small. If the influx fluid is gas it can of course migrate and expand. The expansion may occur when there is little or no pipe left in the hole. The consequences of running pipe into the hole and into swabbed gas must also be considered. Pulling Speeds Tripping speeds must be controlled to reduce the possibility of swabbing. It is normal practice for the Mud Logger to run a swab and surge programme and to make this information available to the Driller. This will provide ample information to reduce the possibility of unforeseen influx occurring. 2-8

V4 Rev March 2002


Mud Properties Controlling the rheology of mud is important. Controlling water-loss to avoid thick wall cake will also help. Trip Margin A safety factor to provide an overbalance to compensate for swab pressure can be: Trip Margin Factor APL psi ––––––––––––––––– = ––––––––––––––––– (psi/ft) True Vert. Depth. ft APL = Annulus Pressure Loss If swabbing has been detected and the well is not flowing a non return valve should be installed and the bit returned to bottom. Flow check each stand. Once back on bottom the well should be circulated and the bottoms up sample checked for contamination. If the well is flowing or the returns from the well are excessive when tripping in then the following should be carried out: •

Install a non return valve. If there is a strong flow then a kelly cock may have to be installed first.

•

Shut the well in.

•

Prepare for stripping.

•

Strip in to bottom.

•

Circulate the well, check bottoms up for contamination.

Continuous monitoring of replacement and displacement volumes is essential when performing tripping. A short wiper trip and circulating the well before pulling completely out of the hole will provide useful information about swabbing and pulling speeds. Useful formulae for calculating the psi reduction per foot of drill pipe pulled are as follows: (mud grad. (psi/ft) x metal disp. (bbls/ft)) Pulling Dry Pipe: psi/ft or dry pipe pulled = –––––––--––––––––––––--––––––––––––––– (casing cap. (bbls/ft) - metal disp. (bbls/ft))

( (

) )

(mud grad. (psi/ft) x metal disp. + cap. (bbls/ft) Pulling Wet Pipe: psi/ft or wet pipe pulled = –––––––--–––––––-–––––-–––––––––-–––––– (casing cap. (bbls/ft) - metal disp. + cap. (bbls/ft)) V4 Rev March 2002

2-9


2.3.3 LOSS OF CIRCULATION Another cause for a kick to occur is the reduction of hydrostatic pressure through loss of drilling fluid to the formation during lost circulation. When this happens, the height of the mud column is shortened, thus decreasing the pressure on the bottom and at all other depths in the hole. The amount the mud column can be shortened before taking a kick from a permeable zone can be calculated by dividing the mud gradient into the overbalance at the top of the permeable kick zone.

H (ft) =

Overbalance (psi) –––––––––––––––––––––– Mud Gradient (psi/ft)

2.3.4 INSUFFICIENT MUD WEIGHT A kick can occur if a permeable formation is drilled which has a higher pressure than that exerted by the mud column. If the overpressurised formations have low permeability then traces of the formation fluid should be detected in the returns after circulating bottoms up. If the overpressured formations have a high permeability then the risk is greater and the well should be shut-in as soon as flow is detected.

2.3.5 ABNORMAL PRESSURED FORMATIONS A further cause of kicks from drilling accidentally into abnormally pressured permeable zones. This is because we had ignored the warning signals that occur, these help us detect abnormal pressures. Some of these warning signals are: an increased penetration rate, an increase in background gas or gas cutting of the mud, a decrease in shale density, an increase in cutting size, or an increase in flow-line temperature, etc. In some areas, there were adequate sands that were continuous and open into the sea or to the surface. In these areas the water squeezed from the shale formations, travelled through the permeable sands and was released to the sea or to a surface outcrop. This de-watering allowed the formations to continue to compact and thereby increase their density.

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Figure 2.7

SEA

PERMEABLE ZONE

NORMAL PRESSURE In other areas, or at other times, the sands did not develop or were sealed by deposition of salt or other impervious formations, or by faulting such as we have indicated here. Although the shale water was squeezed, it could not escape. Since water is nearly incompressible, the shales could not compress past the point where the water in the shale started to bear the weight of the rock above. This section caused a condition in which the weight of the formation - that is, the overburden was borne not by the shale alone, but assisted by the fluids in the shale. In this situation the shale will have more porosity, and a lower density, than they would have had if the now pressured water had been allowed to escape. These formations, both sand and shale, are then overpressured. If a hole is drilled into an overpressured formation, weighted mud will be required to hold back the fluids contained in the pore space. Figure 2.8

SEA

FAULT

ABNORMAL PRESSURE 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 pressures are also termed surpressures, overpressures and sometimes geopressures. More often, they are simply called abnormal pressures.

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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 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 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 CIS. These super pressures can only exist because the internal strength of the rock overlying the super pressured zone assists the overburden load in containing the pressure. The overlying rock can be considered to be in tension. In the Himalayan foothills of 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 pressure in the range of 5870 to 7350 psi at 5250 feet were reported. This equates to a formation pressure gradient of 1.12 to 1.4 psi/ft. 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 expandible 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 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 North Sea Central Graben, overpressures of 0.9 psi/ft have been recorded. One reported case indicated a formation pressure gradient of 0.91 psi/ft in the Jurassic section. In the Jurassic of the Viking Graben, abnormal formation pressure gradients of up to 0.69 psi/ft have been recorded.

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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 Zechsteins salts.

2.3.6 SHALLOW GAS SANDS Kicks from shallow sands (gas and water) whilst drilling in the top hole section with short casing strings can be very hazardous, as documented by many case histories. Some of the kicks from shallow sands are caused by charged formations: poor cement jobs, casing leaks, injection operations, improper abandonments, and previous underground blowouts can produce charged formations.

2.3.7 SPECIAL SITUATIONS a) Drill Stem Testing (DST) The formation test is one of the most hazardous operations encountered in drilling and completing oil and gas wells. The potential for stuck tools, blowouts, lost circulations, etc., is greatly increased. A drill stem test is performed by setting a packer above the formation to be tested, and allowing the formation to flow. Down hole chokes can be incorporated in the test string to limit surface pressures and flow rates to the capabilities of the surface equipment to handle or dispose of the produced fluid. During the course of the test, the bore hole or casing below the packer, and at least a portion of the drill pipe or tubing, is filled with formation fluid. At the conclusion of the test, this fluid must be removed by proper well control techniques to return the well to a safe condition. Failure to follow the correct procedures to kill the well could lead to a blowout. b) Drilling Into an Adjacent Well Drilling into an adjacent well is a potential problem, particularly offshore where a large number of directional wells are drilled from the same platform. If the drilling well penetrates the production string of a previously completed well, the formation fluid from the completed well will enter the wellbore of the drilling well, causing a kick. If this occurs at a shallow depth, it is an extremely dangerous situation and could easily result in an uncontrolled blowout.

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c) Excessive Drilling Rate Through a Gas Sand/Limestone When drilling a gas bearing formation, the mud weight will be gas cut due to the gas breaking out of the pore space of the cuttings near the surface. The severity of the influx will depend on the penetration rate, porosity and permeability, and is independent of mud weight. The importance attached to gas cutting is that gas is entering the wellbore in small quantities, which calls for caution. Degassing is necessary to ensure that good mud is being pumped back into the hole to prevent the percentage of gas from increasing with each circulation, which would allow greater and greater bottom hole hydrostatic pressure reductions. Figure 2.9 Reduction in Hydrostatic Head Due to Gas Cutting of the Mud 18 ppg mud cut 50% to 9.0 ppg Depth

Normal Head 18 ppg mud

Reduced Head

Head Reduction

1,000'

936 psi

866 psi

60 psi

5,000'

4,680 psi

4,598 psi

82 psi

10,000'

9,360 psi

9,265 psi

95 psi

20,000'

18,720 psi

18,615 psi

105 psi

Most of mud cutting is close to surface. Divert flow through choke manifold to prevent belching and to safely contain gas through mud gas separator. Time drill the gas cap to prevent severe gas cutting of mud. Gas cutting alone does not indicate the well is kicking, unless it is associated with pit gain. Allowing the well to belch over the nipple could cause reduction in hydrostatic pressure to the point that the formation would start flowing, resulting in a kick.

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2.4 APPENDIX - HYDRATE FORMATION & PREVENTION 2.4.1 FORMATION OF HYDRATES Hydrates will only form if there is free water present in a system. Hydrates are crystalline water structures filled with small molecules. In oil / gas systems they will occur when light hydrocarbons (or carbon dioxide) are mixed with water at the correct temperature and pressure conditions. A very open, cage-like structure of water molecules is the backbone of hydrates. This structure which bears some resemblance to a steel lattice in a building can theoretically be formed in ice, liquid water, and water vapour. In practice however, hydrates are only formed in the presence of liquid water. The crystal framework is very weak and collapses soon if not supported by molecules filling the cavities in the structures. Methane, Ethane, CO2 and H2S are the most suitable molecules to fill cavities. Propane and Isobutane can only fill the larger cavities. Normal butane and heavier Hydrocarbons are too big and tend to inhibit hydrate formation. Tests indicate that Hydrate formation is comparable with normal crystallisation. ‘Undercooling’ is possible, but the slightest movement within and undercooled mixture, or the presence of a few crystallisation nuclei will cause a massive reaction. Once the crystallisation has started, hydrates may block a flowline completely within seconds. The formation of hydrates is governed by the crude composition, water composition, temperature and pressure. In most cases the crude composition cannot be changed. Hydrates can be dissolved / prevented by a temperature increase or a pressure decrease. A chemical hydrate inhibition can be performed by changing the composition of the water. Under the correct conditions of temperature and pressure, hydrates will form spontaneously. At high pressures, hydrates may form at relatively high temperatures; e.g. at 2900 psi they can begin to form at about 77˚ F . Hydrates do not require a pressure drop to form. However, the refrigeration effect from a small pressure drop, such as a stuffing box leak, may be sufficient to produce optimum pressure and temperature conditions for hydrate formation. Hydrates can form under flowing or static conditions. The first indication of them forming in the tubing or annular flow string is a drop in flowing wellhead pressure followed by an initially slow then progressively rapid drop in wellhead flowing temperature. During well operations, the greatest danger posed by hydrates is the plugging of the tubing string downhole. The biggest risk area for this occurring is on offshore installations from the seabed upwards where temperatures are generally the lowest.

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A hydrate plug in the tubing string under flowing or static conditions results in; being unable to run or pull wireline tools, unable to squeeze or circulate the well dead, and unable to flow the well to remove the hydrates. Also, hydrates may prevent vital equipment, such as the Downhole Safety Valve from functioning correctly. Thus a downhole hydrate plug gives rise to a potentially dangerous situation and must be avoided at all costs.

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2.5 THE FUNCTIONS OF DRILLING MUDS (1) PRIMARY FUNCTIONS: (a) To help maintain the stability of the wellbore, by outward hydrostatic pressure and mud filter cake. (b) To carry the drill cuttings up the annulus and back to the surface by its upward motion and viscosity. (c) To maintain pressure balance in the well during drilling, tripping and other operations. The mud hydrostatic pressure must be at least equal to or greater than the reservoir pore pressure. (d) To cool the bit and drillstring and to lubricate the cutting surfaces at the bit. (e) To hold cuttings in suspension, by its gelling action, when circulation is stopped. (2) SECONDARY FUNCTIONS: (f) To provide a working fluid for downhole motors and turbines and for the transmission of coded downhole signals to the surface (MWD)+. (g) To help to support part of the weight of the drillstring by its buoyancy. (h) To help to prevent mud filtrate invasion of productive formations by an impermeable filter cake. (i) To ease the movement of drillstring in the well and to reduce wear by its lubricity

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PROPERTIES of DRILLING MUDS

Drilling muds need to have some essential properties. Those are : RHEOLOGY: This group of mud properties influences the hydrodynamics of the mud behaviour. It includes: Mud (plastic) viscosity in centipoise units. Mud yield strength in lbf/l00ft2. Gel strength at 10sec and 10 minutes. DENSITY:

This is controlled by the weight additives in the mud. It is of importance in pressure control, drilling rate (ROP) and in wall stability of the well.

FILTRATION: This is the ability of the mud to build a thin layer of filter cake on the wall of the hole. The filter cake controls the outward flow of liquid filtrate from the mud into the reservoir formation. The deeper the penetration of this filtrate into the rock, the more difficult later logging of the well becomes. LUBRICITY:

This is the ability of the mud to provide a degree of lubrication of the rubbing surfaces of the drillstring and the rock or the casing, and so reduce wear. lt is provided by the clays, polymers or oils in mud.

Additionally, the mud needs to have properties of resistivity and corrosion inhibition .

CLASSIFICATION OF DRILLING MUDS Drilling muds can be divided into the following classes: (1): Water-based muds ie fresh water or sea water. (2): Oil-bascd muds: (a) Invert emulsions, with oil:water ratios from 50:50 to 90:10. (b) Low toxic invert emulsions, as in (a) but with low to base oils. (3): Synthetic or pseudo oil-based muds. In addition to muds, gas and stable foams may be used as drilling fluids.

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INGREDIENTS of DRILLING MUDS: All muds have 4 categories of ingredients: (a) A liquid base to support other components (b) A viscosifier, to produce viscosity and gel. (c) A weighting agent, to produce density. (d) Chemicals to control changes to the mud arising from interactions with the drilled formations. MUD CLASSlFICATION: WATER-BASED MUDS. BASE FLUID: Fresh water or sea water or brackish water. (SG = l to 1.03) VISCOSIFIER: Bentonite clays and/or co-polymers. (SG= 2.6) WEIGHTING: Barite (sg = 4.2) or, Magnetite (sg = 5.1) or, Galena (sg= 6.5) CHEMICALS: Caustic soda or lime for pH control. Lignosulfonate derivatives, for thinning. Salts, for inhibition of reactions. Gypsum, for inhibition. Starch and gums. Surfactants. Corrosion inhibitors' etc.

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SOME TYPICAL MUDS: (1) SPUD MUDS: Very basic: Sea water and pre-hydrated clays, or native clays. Used for top-hole sections. Hi pump rates needed to give good holecleaning and wall support. Very low cost/bbl. (2) LIGNOSULFONATE MUDS: Used where active native clays have to be drilled. Lignite materials are added to control the thickening effect of those clays. Give good control of the drilled solids and mud rheology. If sea water is base fluid, pre-hydrated bentonite slurry must be used . (3) LIME ,GYPSUM or CALCIUM TREATED MUDS: Used where shale/clays or anhydrites are present and may cause hole instability. (4) SALT WATER MUDS: Used where salt formations or unstable shales are to be drilled. Sodium or potassium salts (NaC1 or KCI) are used for inhibition. (5) POLYMER MUDS: Use high molecular weight polymers (CMC, hydroxyethyl cellulose) to give viscosity and gel. May be used with small amounts of bentonites to give Low Solids Non-Dispersed muds. Good ROP's and protection against formation damage.

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Raise by adding BENTONITE or C.M.C. Lower by adding WATER (check density) or THINNER Raise by adding BENTONITE

Keep as low as is practically possible 35-50 secs M.F. A.V 12-20 cp PV 10-15cp YP + 9 x mud density kg/L 0’ gel (mud density -1) x 10 10’ gel (mud density -1) x 15

Increase mud viscosity decreases penetration rate

Increase yield point and gel strength decreases penetration rate

a. Viscosity

b. Bingham yield point

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4. Lubricates and cools bit and drill string

3. Protects and supports bore - hole wall by the formation of an impermeable mudcake which also minimise contamination

In unweighted muds < 10 % vol.

In unweighted muds > 90 % vol.

Increases solids content decreases penetration rate

Increased water content Increases penetration rate

b. Solid content

a. Water content

Spud mud + 20 mls Shallow no producing zones 10 mls Below 10,000ft 5mls Hole troubles or producing zones <5 mls

Decreased fluid loss slightly decreases penetration rate

a. Fluid loss

c. Gel Strength

2. Carries out cuttings

Keep as low as possible by continuous removal of unwanted clay, silt, sand and cuttings

Raise by adding WATER

Lower by adding C.M.C. or THINNER

Lower by adding THINNER

Lower by adding WATER (check viscosity)

Raise by adding BARYTES

Has to be calculated from well depth and expected pressures Safety factor: 2-300 psi overpressure ( 1500-2000 KPa)

Increased mud density decreases penetration rate

Mud density

1. Confines formation pressures

Chemicals for control

Recommended value

Effect of property on penetration rate

Relevant property

Function


FUNCTIONS AND PROPERTIES OF OIL WELL DRILLING FLUIDS

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MUD CONTAMINATION: Mud contaminants are extraneous materials which enter the mud during the drilling process, and which alter and degrade the essential mud properties. Mud contaminants arise from: (1) The formations which are drilled. Those contaminants are either solid or liquids or gases from: (a) Shales: (b) Limestones,dolomites and anhydrites: (c) Salt formations: (d) Formation brines: (e) Hydrogen sulphide, carbon dioxide: (f) Retained small particles (< 2 microns) of cuttings. (2) Cement: this is a potential problem when cementing casings and on drilling out "green" cement plugs. Those contaminants will generally cause adverse reactions in the muds ( particularly water-based muds), such as: Flocculation, where dispersed bentonite clay platelets can aggregate, causing (i) rising gel strengths; (ii) high rates of fluid loss from mud; (iii) thick,soft filter cake. Viscosity changes. .

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LOW TOXIC OIL BASED MUDS: Generally all oil-based muds in Western activities are of the low-toxic base oil types. Many governments have stringent regulations which limit or ban the discharge of oil impregnated cuttings. Oil to water ratios lie in the range of 50%: 50% to 90%: 10% . A typical LT OBM would have the following categories of constituents: LT base oil (of the paraffin series). Water, which has calcium chloride (CaCl) dissolved to 250,000 ppm or which is saturated with salt (NaCI) to 315,000 ppm. Primary emulsifier. Organophilic clay ( for viscosity). Secondary emulsifier and wetting agent. Lime. Weighting agent ( barite) At atmospheric conditions, the filter cake from an OBM will be very thin and the filtrate loss negligible. LT OBM's are generally more expensive than straight water-based muds and, when diluted, base oil should be used. Rig modifications are necessary to handle LT OBM's. Unlike water based muds, there is a problem relating to the solubility of a gas kick in the base oil of the mud. This problem is much more acute at bottom hole pressures around 4000 psi than at high bottom hole pressures. Due to the gas solubility, the true volume of an influx may be substantially greater than the measured pit gain. This problem is compounded when the dissolved gas breaks out of solution at the bubblepoint pressure, when large volumes of gas can be released within the annulus or downstream of the choke.

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2.6 EXTRACTS FROM API RP59 6.1 Introduction. Loss of primary well control most frequently results from: 1) failure to keep the hole full; 2) swabbing; 3) insufficient drilling fluid density; and/or 4) lost circulation. These problems can occur during any operation conducted on a well. The goal of well control is to prevent a well kick (influx of formation fluid into the wellbore) from becoming a blowout (uncontrolled flow of formation fluid). 6.2 Conditions Necessary for a Kick. The two conditions that must be present in the wellbore for a kick to occur are 1) the pressure in the wellbore at the face of the kicking formation must be less than the formation pressure; and 2) the kicking formation must have sufficient permeability to allow flow into the wellbore. To maintain primary well control, drilling personnel should utilise all techniques at their disposal to ensure that the hydrostatic pressure in the wellbore is always greater than the formation pressure. A number of conditions which can cause or contribute to well kicks are discussed in Paras 4.3 through 4.15. 6.3 Hole Not Full of Drilling Fluid. When the fluid level in the wellbore is allowed to drop or is maintained with a lighter density fluid, the resultant reduced hydrostatic head can allow fluid entry from the formation. The rig should have drilling fluid measuring devices to determine that proper fluid replacement or displacement occurs when pulling or running pipe. The type of fluid measuring equipment used should be influenced by the anticipated well control operations involved in drilling the well. 6.4 Tripping Out of the Hole. When pulling pipe, its displacement volume should be replaced with the proper amount of drilling fluid to maintain constant hydrostatic pressure. Any significant reduction in hydrostatic pressure may result in loss of primary control. If the hole fails to take the proper amount of drilling fluid, hoisting operations should be suspended and an immediate safe course of action determined while observing the well. This usually requires returning to bottom and circulating the hole. The frequency of filling the hole during tripping operations is critical in maintaining primary control. The hole should be completely filled at intervals that will prevent an influx of formation fluid. Continuous filling or filling after each stand of drill pipe may be advisable. The hole should be filled after each stand of drill collars. When the hole is filled continuously, an isolated drilling fluid volume measurement facility (such as a trip tank) must be used. 6.5 Tripping In the Hole. In running pipe back in the hole, the drilling fluid volume increase at the surface should be no greater than predicted displacement. Some holes take significant volumes of drilling fluid during trips because of seepage loss. It is necessary to keep a trip book (refer to Para. 10.3 and Table 10.1) for ready comparison to determine if an abnormal condition occurs. The gauging of fluid returns and comparison with prior trip records should provide a warning of possible loss of primary well control. The hole and fluid returns should be checked at frequent intervals. 2 - 24

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6.6 Out of the Hole. Time with pipe out of the hole should be minimised. Particular care should be taken when a servicing tool, such as a core barrel, with its length too great to clear the ram closure zone and/or its outside diameter too large to fit the pipe rams, to have the necessary crossover connection(s) readily available so that correct pipe movement can be effected to be able to close more than the annular blowout preventer. In case of equipment repair on drilling rigs, the pipe should be run at least back to the last easing shoe, if possible, before repairs are undertaken. In well servicing operations, when making equipment repairs, effecting routine maintenance, or shutting down overnight, the pipe should be run to a sufficient depth to ensure that the well can be controlled. 6.7 Swabbing. When pipe is pulled from a well, a reduction in bottom-hole hydrostatic pressure (swabbing) may occur. Bottom-hole pressure reduction of several hundred pounds per square inch (psi) can occur when swabbing takes place. This pressure reduction, which can be sufficient to permit the entry of formation fluid into the wellbore, is one of the major reasons for losing primary well control. This type of swabbing action should not be confused with the more obvious concept of actually pulling fluid from a well with a balled up bit or packer, or swabbing in a producing well through tubing. When pipe is pulled from a well, swabbing can be difficult to detect. The well may take some fluid as the pipe is withdrawn but less than the complete pipe displacement. The detection of swabbing, therefore, can only be done by accurately measuring the drilling fluid added to the hole as pipe is pulled. Three prime factors in controlling swabbing are: 1) drilling fluid properties; 2) rate of pulling pipe; and 3) drill string and hole configurations. 6.8 Trip Margin. The use of a trip margin is encouraged to offset the effects of swabbing. The additional hydrostatic pressure will permit some degree of swabbing without losing primary well control. 6.9 Short Trip. After tripping and circulating “bottoms-up,” the amount of gas, salt water, or oil contamination will enable the evaluation of operating practices affecting swabbing. Adjustments in pulling speed, drilling fluid flow properties, and/or drilling fluid density may be warranted. A short trip and circulating “bottoms-up” before pulling out of the hole can also be used to determine the system’s swabbing characteristics. 6.10 Insufficient Drilling Fluid Density. The condition where formation pressure exceeds existing hydrostatic pressure in the wellbore is referred to as underbalance and can be caused be insufficient drilling fluid density. 6.11 Lost Circulation. Lost circulation occurs in both drilling and well servicing operations and may quickly destroy the hydrostatic overbalance that constitutes primary control. The loss can result from natural or induced causes. Natural causes include fractured, vugular, cavernous, subnormally-pressured, or pressuredepleted formations. Induced loss can result from mechanical formation fracturing resulting from 1) excessive drilling fluid density, 2) excessive annular circulating pressure, 3) pressure surges related to running pipe or tools. 4) breaking circulation, or 5) packing off in the annulus. V4 Rev March 2002

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6.12 Drill Stem Testing. Drill stem tests are performed by setting a packer above the formation to be tested and allowing the formation to flow. During the course of testing, the borehole or casing below the packer and at least a portion of the drill pipe or tubing is filled with formation fluid. At the conclusion of the test, the fluid in the test string above the circulating valve must be removed by proper well control techniques, such as reversing, to return the well to a safe condition. Depending on the length of hole below the packer, type of fluid entry, and formation pressure, the normal drilling hydrostatic overbalance can be reduced or lost. Caution should be exercised to avoid swabbing when pulling the test string because of the large diameter packers. 6.13 Drilling Into an Adjacent Well. Frequently, a large number of directional wells are drilled from the same offshore platform or onshore drilling pad. If a drilling well penetrates the production string of a previously completed well, the formation fluid from the completed well may enter the wellbore of the drilling well, causing a kick. Special care should be exercised to avoid a collision course with another well. 6.14 Excessive Drilling Rate Through a Gas Sand. Even if the drilling fluid density in the hole is sufficient to control gas zone pressure, gas from the drilled cuttings will mix with the drilling fluid. Excessive drilling rate through a shallow gas zone or coal bed can supply sufficient gas from cuttings to reduce the hydrostatic pressure of the drilling fluid column through a progressive combination of density reduction and drilling fluid loss from “belching” to the point that the formation will begin flowing into the wellbore. 6.15 Others. Primary control can also be lost while performing operations other than circulating, drilling, or running and pulling pipe, loss of well control can occur during coring, perforating, fishing, performing primary or remedial cementing, running casing or liner operations, or when differential fill equipment malfunctions. All such operations require the accurate measurement and control or drilling fluid replaced or displaced in the well to maintain primary control. Complications can occur in primary control during floating drilling operations due to distorted readings caused by motion and heave. The measurement of drilling fluid volume and flow rate is most critical in floating operations and requires pit level monitoring devices (floats) located in the centre of the pits or multi-floats with sequential integration utilised. A trip tank and pit watcher should be considered if vessel movement creates any problem in measuring drilling fluid requirements on trips. 6.16 Special Situations. The accurate prediction of pressure gradients, particularly abnormal pressure, and the prevention of an insufficient drilling fluid density situation, are highly desirable but not always attainable. In some situations of insufficient drilling fluid density, operations can be safely handled and proceed without increasing drilling fluid density, yet maintain control (underbalanced drilling). An abnormally pressured gas zone with low productivity (e.g., shale gas) is a possible example where the well will not flow appreciably but gas exists after 2 - 26

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a trip which may require use of blowout prevention equipment and/or rotating heads. Sometimes fluid influx will occur when circulation is stopped, but will not occur during drilling operations due to the effect of annular circulating pressure. In this instance, successful operations usually require an increase in drilling fluid density or, in some fields, the use of a lighter drilling fluid and another heavier drilling fluid to control the well on trips. WELL CONTROL WARNING SIGNALS 6.17 General. Well control warning signals can be classified in three major general categories as follows: A. Previous Field History and Drilling Experiences. 1. Depth of zones capable of flowing. 2. Formation gradients. 3. Fracture gradients. 4. Formation content. 5. Formation permeability. 6. Intervals of lost circulation. B. Physical Response From the Well. 1. Pit gain or loss. 2. Increase in drilling fluid return rate. 3. Changes in flowline temperature. 4. Drilling breaks. 5. Variations in pump speed and/or standpipe pressure. 6. Swabbing. 7. Drilling fluid density reduction. 8. Effects of connections, short trip, and trip on shows and gains. 9. Hole problems indicating underbalance (i.e., tight hole, packing-off, sloughing). 10. Excessive pressure or pressure changes between casing strings. V4 Rev March 2002

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C. Chemical and Other Technical Responses From the Well. 1. Chloride changes in the drilling fluid. 2. Oil show. 3. Gas show (chromatograph). 4. Formation water. 5. Shale density. 6. Electric logs. 7. Drilling equation exponents. 6.18 Volume of Drilling Fluid to Keep the Hole Full on a Trip is Less Than Calculated or Less Than Trip Book Record. This condition is usually caused by formation fluid entering the wellbore due to the swabbing action of the drill string. As soon as swabbing is detected, the drill string should be run back to bottom. Circulate and condition the drilling fluid to minimise further swabbing. It may be necessary to increase the drilling fluid density, but this should not be the first step considered because of the inherent potential problems of causing lost returns or differential sticking. 6.19 Gain in Pit Volume. An unaccounted volume gain in the drilling fluid pit(s) is an indication that a kick may be occurring. As the formation fluid feeds into the wellbore, it causes more drilling fluid to flow from the annulus than is pumped down the drill string, thus the volume of fluid in the pit(s) increases. 6.20 Increased Flow From Annulus. If the pumping rate is held constant, the flow from the annulus should be constant. If the annulus flow increases without a corresponding change in pumping rate, the additional flow is caused by formation fluid(s) feeding into the wellbore or gas expansion. 6.21 Sudden Increase in Bit Penetration Rate. A sudden increase in penetration rate (drilling break) is usually caused by a change in the type of formation being drilled: however, it may also signal an increase in formation pore pressure. Increased penetration rates due to higher pore pressures are usually not as abrupt as formation drilling breaks, but they can be. In order to be certain that gradual increases in pore pressure are recognised, a penetration rate versus depth curve plot is recommended to highlight the trend of increasing pore pressure. 6.22 Change in Pump Speed or Pressure. The initial surface indication that a well kick has occurred could be a momentary increase in pump pressure. The pump pressure increase is seldom recognised because of its short duration, but it has been noted on some pump pressure recording charts after a kick was detected. 2 - 28

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The pressure increase is followed by a gradual decrease in pump pressure, and may be accompanied by an increase in pump speed. As the lighter formation fluid flows into the wellbore, the hydrostatic pressure exerted by the annular column of fluid decreases, and the drilling fluid in the drill pipe tends to U-tube into the annulus. When this occurs, the pump pressure will drop and the pump speed will increase. The lower pump pressure and increase in pump speed symptoms are also indicative of a hole in the drill string, commonly referred to as a washout. Until a confirmation can be made whether a washout or a well kick has occurred, a kick should be assumed. 6.23 Gas-cut Drilling Fluid. Gas-cut drilling fluid often occurs during drilling operations and can be considered one of the early warning signs of a potential well kick: however, it is not a definite indication that a kick has occurred or is impending. An essential part of analysing this signal is being able to determine the downhole conditions causing the drilling fluid to be gas-cut. Gas-cut fluid occurs as a result of one or more of the following downhole conditions: 1) drilling a gas-bearing formation with the correct drilling fluid density in the hole (drilled gas); 2) swabbing while making connections or making a trip (trip or connection gas); and 3) influx of gas from a formation having a pore pressure greater than the pressure exerted by the drilling fluid (gas flow). A. Drilled Gas. When the hydrostatic pressure exerted by the drilling fluid is greater than the pore pressure of a gas-bearing formation being drilled, there will be no influx of gas from the formation. Nevertheless, gas from the drilled cuttings will usually mix with the drilling fluid causing the returns to be gas cut. As gas is circulated up the annulus, it expands slowly until just before reaching the surface. The gas then undergoes a rapid expansion, resulting in the drilling fluid density being reduced considerably upon leaving the annulus. In some cases this reduction in density can be quite extreme but it may not mean that a kick is about to occur. Usually, only a small loss in hydrostatic pressure results because the majority of gas expansion occurs in the top of the hole. Drilling fluid of proper density is still maintained in most of the hole. Quite often when the drilled gas reaches the surface, the annular preventer must be closed and the drilling fluid circulated through the open choke manifold. This prevents the expanding gas from “belching” fluid through the bell nipple. If “belching” continues, the hydrostatic head will be reduced due to loss of drilling fluid from the hole. B. Trip or Connection Gas. After circulating “bottoms-up” following a trip or connection, a higher level of gas entrained in the drilling fluid returns may cause a short duration density reduction or gas unit increase. If the well did not flow when the pumps were stopped during the trip or connection, it can be reasonably assumed that the gas was swabbed into the wellbore by the pipe movement. These symptoms can indicate increasing formation pressure when compared with previous trips and connections.

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C. Gas Flow. Influx from a gas zone while drilling is a serious situation. While drilling, the formation pore pressure must exceed the hydrostatic pressure of the drilling fluid plus the circulating friction losses in the annulus for gas from the formation to flow into the wellbore. Once influx begins, continued circulation without the proper control of surface pressures will induce additional flow, since the density of the hydrostatic column (annulus) is continually lessened by the flow of formation fluid and expansion of gas. 6.24 Liquid-cut Drilling Fluid. When a permeable liquid-bearing formation having pore pressure greater than the drilling fluid hydrostatic pressure is encountered, fluid will feed into the wellbore. Depending upon the pressure differential between the formation and the drilling fluid, influx may be detected by: 1) a gain in pit volume, 2) lower density returns, 3) a change in drilling fluid chlorides, and/or 4) an increase in rotary torque. The volume of liquid contained in the cuttings is usually so small that unless accompanied by gas, it will not significantly affect the drilling fluid density. NOTE: A rare exception to this rule is the very low permeability formation which can be drilled while allowing a continuous small influx to occur. This type of underbalanced drilling is only practicable in certain well-known drilling areas where the geology is sufficiently known to allow preplanning for the rig equipment and drilling practices necessary.

ADDITIONAL CAUSES OF KICKS UNIQUE TO SUBSEA OPERATIONS 9.2 Loss of Integrity. Wellbore hydrostatic pressure is a function of height and density of the drilling fluid column from the flowline to the depth of interest. If a riser fails, leaks, or becomes disconnected, the drilling fluid gradient in the riser is lost and replaced by a sea water gradient (approximately 0.445 psi/ft — 8.56 Ib/ gal) from the point of failure to sea level. The loss of wellbore hydrostatic pressure associated with this situation can sometimes be sufficient to allow the well to flow. The first response should be to close the blowout preventers. In some situations, the drilling fluid density may be sufficient to compensate for the loss of hydrostatic pressure. If not, the loss of hydrostatic pressure should be restored prior to opening the blowout preventer. 9.3 Trapped Gas Below Blowout Preventers Subsequent to control operations during which gas is circulated out the choke line, free gas will remain trapped below the closed preventer. If the closed preventer is an annular preventer, it is possible for this volume of gas to be quite significant. In order to prevent a rapid unloading of the riser due to trapped gas when the annular preventer is opened or the introduction of a secondary kick due to light density drilling fluid in the riser, close the uppermost rams below the choke line and close the diverter. Open the preventer above the trapped gas and allow this gas to rise toward the surface. Displace the riser with kill fluid and reopen the rams. It may be necessary in extreme cases to close the bottom rams to isolate the hole and fill the riser by circulating through the kill line. This problem becomes more severe with increased water depth and/or preventer size. 2 - 30

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2.7 - WORKSHOP 2 SCORE 1.

There are a variety of mechanisms that can cause abnormal formation fluid pressures. List 4 of the principle causes below. Answer

2.

(a) ———————— (b) ———————— (c) ———————— (d) ————————

2

Shown below is a pressure versus volume plot of a leak off test.

PRESSURE (PSI)

1200 1000 800 600 400 200 0 VOLUME The leak off was carried out with a 10.6 ppg mud. The casing shoe is at 4000ft TVD. a.

b.

c.

d.

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What is the maximum pressure that the exposed formations below the shoe can support? ANSWER.................

2

What is the “Fracture Gradient?” ANSWER.................

2

What is the maximum mud weight? ANSWER.................

2

If drilling was resumed and the mud weight was increased to 12.6 ppg. Calculate M.A.A.S.P ANSWER................. 2

2 - 31


3.

M.A.A.S.P. The maximum allowable annular surface pressure should be re-calculated.. a. b. c. d. e.

SCORE

At the start of each shift As soon as possible after a drilling break When approaching a suspected transition zone When the mud weight has been increased in the system If a kick has occurred and the well is shut-in ANSWER.................

4.

2

The calculated M.A.A.S.P. value is relevant.. a. When the influx is in the open-hole section b. As the influx approaches the surface ANSWER.................

5.

SCORE

Given the following data: Depth Bit size Shoe depth Mud weight

2

10000ft TVD 8 1/2" 8500ft TVD 12.6 ppg

Collars - 600ft. capacity Metal displacement Drill-pipe 5" capacity Metal displacement Casing/pipe annular capacity Casing capacity One stand of drill-pipe

= = = = = = =

0.0077 bbl/ft 0.03 bbl/ft 0.0178 bbl/ft 0.0075 bbl/ft 0.0476 bbl/ft 0.0729 bbl/ft 94ft.

Assuming the 12.6 ppg mud gives an over-balance of 200 psi. a.

If 10 stands of pipe are removed “dry” without filling the hole, what would be the resultant reduction in bottom-hole pressure? ANSWER...........................

b.

If 5 stands of pipe had been pulled “wet” without filling the hole, the resultant reduction in bottom-hole pressure would be. ANSWER...........................

c.

3

If prior to tripping a 20 barrel slug of 14.6 ppg mud was displaced to prevent a wet trip, what would be the expected volume return due to the U-tubing of the heavy mud? ANSWER...........................

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3

2

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6.

Prior to tripping out of the hole a trip tank and pump are lined up to keep the hole full as the pipe is removed. The trip tank contains 30 barrels of mud. After pulling 10 stands of pipe the level in the trip tank is 27 barrels. (Use data given in Question 6). Would the safest option be.. a. b. c. d.

To continue tripping but flow-check when bits at shoe. Stop and shut the well in. If no pressures seen open the well up and continue tripping. Flow-check. If no flow, go back to bottom and circulate. Flow-check. If no flow, continue tripping ANSWER............................

7.

A well can be induced to flow by swabbing. Swabbing is the reduction of bottom hole pressure due to the effects of pulling pipe. List below 3 conditions that can cause swabbing. Answer

8.

2 SCORE

(a) ——————— (b) ——————— (c) ———————

2

A drill string consist of 5" 20 lb/ft drill-pipe and 8 1/2" drill-collars. The spare kelly cock has 4 1/2" I. F. thread connections. What crossover sub is required for the collars? ANSWER..........................

9.

A fixed rig is set in 300ft of sea water. The marine conductor has been set X ft below the sea-bed. The flow line is 65ft above the mean sea-level. The strength of the sub-sea formations is 0.68 psi/ft. Sea-water gradient is 0.445 psi/ft. It is proposed to drill with 9.2 ppg mud. What is the minimum depth that the conductor has to be set below sea-bed to prevent losses? ANSWER.............................

10.

8

An over-balance or trip margin is added to the mud. When tripping this will prevent a loss of B.H.P. due to the swabbing effect of pulling the pipe. ANSWER. TRUE/FALSE

11.

2

2

Assume casing is set at 4800ft TVD/MD and that gas sands were encountered at 5000ft and at 8500ft. If the formation pressure gradient at 5000ft is 0.47 psi/ft and at 8500ft it is 0.476 psi/ft. What mud weight is required to give an over-balance or trip margin of 200 psi? ANSWER............................

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4 2 - 33



(a) (b) (c) (d) (e)

Under compacted shales Thick gas sands Faults Diaprism salt domes Shape of reservoir structure

2.

Surface pressure = 1100 psi a.

(CSG TVD x MUD WT x .052) + Surface pressure = (4000 x 10.6 x .052) + 1100 = 3305 psi

b.

Frac g = Max press ÷ CSG TVD = 3305 ÷ 4000 = 0.826 psi/ft

c.

Max Mud Wt = Frac g ÷ .052 = .826 ÷ .052 = 1 5.88ppg

d.

MAASP

a.

Mud g x Met Disp ————————— CSG Cap - Met Disp

= (Max mud wt - Drlg mud wt) x .052 x CSG TVD = (15.88 - 12.6) x .052 x 4000 = 682 psi

3. d. 4. a. 5.

=

.655 x .0075 ————— .0729 – .0075

=

.0751 x 940 b.

=

=

.0751 psi/ft

71 psi

Mud g x (Met Disp + pipe cap) ——————————————— Ann Cap =

2 - 34

.0049 ——— .0654

.655 (.0075 + .0178) = ————————— .047

.3525 psi/ft

470ft x .3525psi/ft

166 psi

=

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c.

Dry pipe vol

=

=

=

Slug vol x (slug wt) ————— - 1 (mud wt) 20 X

(

14.6 ———– – 1 12.6

3.17 bbls

6.

c.

7.

(a) (b) (c)

8.

4 1/2" if box - 6 5/8" reg pin.

9.

(Hyd mud to sea bed) - (Hyd sea water) —————————————————— (Frac g - Mud g) = =

)

Pulling speed. Mud Properties, viscosity - Gel strength. Profile of hole (Wellbore geometry).

(365 x 9.2 x .052) - (300 x .445) ————————————— (.68 - .478) 41.1 —— .202 203 ft.

10.

False.

11.

Mud Wt to give 200 psi overbalance = 5000 x .47 psi/ft = 2350 + 200 = 2550 ∴ 2550 ÷ 5000 ÷ .052 =

9.8 ppg

If the 200 psi is to overbalance formation pressure at 8500ft mud wt would be 9.6 ppg. This would overbalance the sands at 5000ft by 148 psi.

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SECTION 3 :

KICK INDICATORS Page

3. 0

Objectives

1

3. 1

Early Warning Signs

1

3. 2

Increase in Drilling Rate of Penetration Drilling Break

1

3. 3

Increase Torque and Drag

2

3. 4

Decrease in Shale Density

2

3. 5

Increase in Cutting Size and Shape

3

3. 6

Mud Property Changes

3

3. 7

Increase in Trip, Connection and a Background Gas

4

Change in the Temperature of the Return Drilling Mud

5

3. 9

Decrease in D-Exponent

7

3.10

Positive Kick Signs

8

3.11

Hydrocarbon Kick Behaviour

10

3.12

Workshop 3

15

3. 8

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WELL CONTROL for the Rig-Site Drilling Team SECTION 3 : KICK INDICATORS

KICK INDICATORS 3.0 OBJECTIVES The objectives of this section are to review the indication of a kick. Early warning signs will be covered as well as positive kick signs.

3.1 EARLY WARNING SIGNS The alertness in determining early warning signs in well control is of the upmost importance to wellbore safety. Careful observance and positive reaction to these signs will keep the well under control and prevent the occurrence of a well flow situation. The various signs that have been recorded as early warning indicators are not consistent in all situations. The signs however may have to be used collectively as one indicator may not accurately provide the warning of getting into an unbalanced situation. Even though the series of signs may change between wells, early warning indications can be found from the following list. • • • • • • • •

Increase in drilling rate of penetration. Increase torque and drag. Decrease in shale density. Mud property changes. Increase in cutting size and shape. Increase in trip, connection and/or background gas. Increase in the temperature of the return drilling mud. Decrease in D-exponent.

3.2 INCREASE IN DRILLING RATE OF PENETRATION - DRILLING BREAK When drilling ahead and using consistent drilling parameters, as the bit wears, a normal trend of decrease penetration rate should occur. If the differential pressure between the hydrostatic pressure of the drilling fluid and formation pore pressure decreases, an increase in the drilling rate occurs as the chip hold down effect is reduced. A general and consistent increase in penetration rate is often a fairly good indicator that a transition zone may have been penetrated. A rapid increase in penetration rate may indicate that an abnormal pressure formation has been entered and an underbalance situation has occurred.

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3-1


3.3 INCREASED TORQUE AND DRAG Increased drag and rotary torque are often noted when drilling into overpressured shale formations due to the inability of the underbalanced mud density to hold back physical encroachment of the formation into the wellbore.

Figure 3.1

∆W –––– drag (up)

Drag and rotating torque are both indirect and qualitative indicators of overpressure. They are also indicators of hole instability and other mechanical problems. Torque and drag trend increases often indicate to the driller that a transition zone is being drilled. Up drag and down drag as well as average torque figures should be recorded on each connection. These trends are valuable when comparing other trend changes.

∆W –––– drag (down)

3.4 DECREASE IN SHALE DENSITY The density of shale normally increases with depth, but decreases as abnormal pressure zones are drilled. The density of the cuttings can be determined at surface and plotted against depth. A normal trend line will be established and deviations can indicate changes in pore pressure.

3-2

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3.5 INCREASE IN CUTTING SIZE AND SHAPE In transition zones or in abnormally pressured shales (sandy shales and bedding sand streaks) the shales break off and fall into hole because of under balanced condition (pore pressure greater than mud hydrostatic pressure). Water wetting may further aggravate this problem. Changes in the Shape of Shale Cuttings can occur as an underbalanced situation is developing. The particles are often larger and may be sharp and angular in the transition zone. Extra fill on bottom may coincide with the trend change. Severe sloughing will often cause changes in pressure and stroke relationship. Normally pressured shales produce small cuttings with rounded edges and are generally flat, while cuttings from an over pressured shale are often long and splintery with angular edges. As reduction of hydrostatic differential between the pore pressure and bottomhole pressure occurs, the hole cuttings will have a greater tendency to come off bottom. This can also lead to shale expansion causing cracking, and sloughing of the shales into the wellbore. Changes in cuttings shape and cuttings load over the shakers needs to be monitored at surface.

3.6 MUD PROPERTY CHANGES Water cut mud or a chloride (and sometimes calcium) increase that has been circulated from bottom always indicates that formation fluid has entered the wellbore. It could be created by swabbing or it could indicate a well flow is underway. Small chloride or calcium increases could be indicative of tight (nonpermeable) zones that have high pressure. In certain type muds, the viscosity will increase when salt water enters the wellbore and mixed with the mud. This is called flocculation because the little molecules of mud solids, which are normally dispersed, form little “groups” called flocs. These flocs cause viscosity and gel increases. In other type muds you might see a viscosity decrease caused by water cutting (weight decrease). This is true when operating with low pH salt saturated water base muds. In oil muds, any water contamination would act as a “solid” and cause viscosity increases. Gas cut mud would be fluffy and would have higher viscosities (and lower mud weight). IT IS ESSENTIAL TO KNOW THAT TREND CHANGES ARE MORE IMPORTANT THAN ACTUAL VALUE OF THE CHANGE.

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3-3


3.7 INCREASE IN TRIP, CONNECTION AND A BACKGROUND GAS Return mud must be monitored for contamination with formation fluids. This is done by constantly recording the flowline mud density and accurately monitoring gas levels in the returned mud. Gas cut mud does not in itself indicate that the well is flowing (gas may be entrained in the cuttings). However, it must be treated as early warning of a possible kick. Therefore pit levels should be closely monitored if significant levels of gas are detected in the mud. An essential part of interpreting the level of gas in the mud is the understanding of the conditions in which the gas entered the mud in the first place. Gas can enter the mud for one or more of the following reasons: •

Drilling a formation that contains gas even with a suitable overbalance.

•

Temporary reduction in hydrostatic pressure caused by swabbing as pipe is moved in the hole.

•

Pore pressure in a formation being greater than the hydrostatic pressure of the mud column.

Gas due to one or a combination of the above, can be classified as one of the following groups: Drilled Gas When porous formations containing gas are drilled, a certain quantity of the gas contained in the cuttings will enter the mud. Gas that enters the mud, unless in solution with oil base mud and kept at a pressure higher than its bubble point, will expand as it is circulated up the hole, causing gas cutting at the flowline. Gas cutting due to this mechanism will occur even if the formation is overbalanced. Raising the mud weight will not prevent it. It should be noted that drilled gas will only be evident during the time taken to circulate out the cuttings from the porous formation.

3-4

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Connection Gas Connection gases are measured at surface as a distinct increase above background gas as bottoms up occurs after a connection. Connection gases are caused by the temporary reduction in effective total pressure of the mud column during a connection. This is due to pump shut down and the swabbing action of the pipe. In all cases, connection gases indicate a condition of near balance. When an increase trend of connection gases are identified, consideration should be given to weighting up the mud before drilling, operations continue and particularly prior to any tripping operations. Trip Gas Trip gas is any gas that enters the mud while tripping the pipe with the hole appearing static. Trip gas will be detected in the mud when circulating bottoms up occurs after a round trip. If the static mud column is sufficient to balance the formation pressure, the trip gas will be caused by swabbing and gas diffusion. Significant trip gas may indicate that a close to balance situation exists in the hole. Gas Due to Inadequate Mud Density Surface indication of an underbalanced formation depend on the degree of underbalance, as well as the formation permeability. Drilling of a permeable formation that is significantly overbalanced will cause an immediate flow increase followed by a pit gain.

3.8 CHANGE IN THE TEMPERATURE OF THE RETURN DRILLING MUD The temperature will normally take a sharp increase in transition zones. The circulating rate, elapsed time since tripping and mud volume will influence flowline temperature trends. The temperature gradient in abnormally pressured formations is generally higher than normal. The temperature gradient decreases before penetrating the interface and, therefore marked differences can give and early indication of abnormal pressures. This is usually a surface measurement which has a tendency to be influenced by operating factors. Figure 3.2 shows plots of temperature increase while penetrating an abnormal pressure formation.

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3-5


Figure 3.2 Flowline Temperature Data 8

6

DEPTH 1000 ft

DEPTH 1000 ft

5

∆T = 0.53 °F 100'

7

9 ∆T = 0.23 °F 100'

10

∆T = 4.33 °F 100'

8

11

TOP OF ∆T = 2.08 °F 100' ABNORMAL PRESSURE ZONE

TOP OF ABNORMAL PRESSURE ZONE 9 90

100

110

120

12 110

130

120

FLOWLINE TEMPERATURE = °F

Temperature data from Gulf Coast well

150

160

3

∆T = 0.39 °F 100'

8

9

DEPTH 1000 ft

DEPTH 1000 ft

140

Temperature data from South Texas well

7

10

130


TOP OF ABNORMAL PRESSURE ZONE

130

140

∆T = 0.70 °F 100' 5

6

∆T = 3.38 °F 100'

11 120

4

150

∆T = 10.0 °F 100' TOP OF ABNORMAL PRESSURE ZONE

7 100

160


110

120

130

140

150


Temperature data from Pacific Coast well

Temperature data from South China Sea well

DEPTH 1000 ft

1 ∆T = 0.43 °F 100'

2

∆T = 5.20 °F 100' 3 TOP OF ABNORMAL PRESSURE ZONE

4

5 70

90 100 110 80 FLOWLINE TEMPERATURE = °F

120

Temperature data from North Sea well

3-6

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3.9 DECREASE IN D-EXPONENT The D-Exponent will be plotted by the well loggers and maintained current at all times. This value was introduced in the mid sixties to calculate a normalised penetration rate in relation to certain drilling parameters.

d

=

log (R/60N) –––––––––––––– log (12W/10°D)

Where: R N W D d

= = = = =

rate of penetration, ft/hr rotary speed, rpm weight on bit, lbs bit size, ins D-exponent

The D-exponent may be corrected and normalised for mud weight changes and/ or ECD (equivalent circulating density) by the following:

dc

=

d x normal pressure (ppg) ––––––––––––––––––––––– mud weight or ECD (ppg) Figure 3.3 SAMPLE PLOT OF Dc EXPONENT vs. DEPTH 1.0

1.5

2.0

10 -

Depth (1000 ft)

A plot of Dc-Exponent versus depth in shale sections, has been used with moderate success in predicting abnormal pressure. Trends of Dc-exponent normally increase with depth, but in transition zones, its value decreases to lower than expected values. Mud logging companies have further variations/models which try to normalise for other parameters (such as bit wear and rock strength) to varying degrees of success. An illustration of a Dc plot is attached as figure 3.3.

11 -

Normal Trend Line

12 -

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9

10

11

12

13

14

15

16

17

13 -

3-7


3.10 POSITIVE KICK SIGNS A kick occurs when the hydrostatic pressure of the mud column in the well is less than the formation pressure provided that the formation has the ability to produce. A kick is a positive indicator that formation fluid is entering the wellbore and Secondary Well Control must be initiated. Recognising a Kick While Drilling Flow into the wellbore causes two changes to occur in the mud circulating system: •

Increase of active mud system volume.

•

The mud return flow rate exceeds the mud flow rate into the well.

Since a rig’s fluid system is a closed system, and increase in returns detected by a flow monitoring system will also be indicated by a gain in pit level. Detecting a change in pit level may be done by visual observation. This means placing some type of pit level marker in the tank, then posting someone to keep a constant watch. From your own experience, you know that to keep a constant watch on the pit level is next to impossible. This is especially true during trips, when most kicks occur. A more accurate and reliable method is to use any of the several pit level measuring instruments with the recorder mounted at the driller’s console and supported by the mud logger’s monitoring system. This allows a constant watch on the pit level by the driller, both while tripping and drilling. Good communication between crew members is essential on the rig. Drillers should make sure crew hands notify them if they do anything to change the level in the pits. If crew hands are adding volume to the pits, they should also notify the driller when they stop adding volume. When drilling a formation containing gas, a minor pit level rise will be noted because of the core volume of gas being drilled. However, this will occur only as the gas nears the surface, and is due to the drilled gas expanding and is not necessarily an indication that the well is underbalanced. The timing of the increase in pit volume is important in distinguishing between a true kick and gas expansion only. The hole will also take the same volume of fluid that it gave up, after the gas bubble has reached the surface. However, if there is any question as to the cause of the pit gain, stop the pump and check the well for flow. On trips, the drill crew should be able to recognise a 5-barrel kick or less. During drilling, the crews are generally able to recognise a 10 barrel kick or less. The size or severity of a kick depends on the volume of foreign fluid allowed to enter the wellbore, which depends on the degree of underbalance, the formation permeability, and the length of time it takes the drilling crew to detect that the well is kicking.

3-8

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Recognising a Kick While Tripping Flow into the wellbore will cause improper hole fill up, if this is seen a flow check should be performed. •

If the flow check is positive then the well should be shut in.

•

If the flow check is negative the drill string should be run back to bottom to circulate bottoms up (stripping may have to be used here).

Trip tanks are recognised to be the safest and most reliable method of monitoring mud volumes on trips. It is recommended that a continuous hole fill up be used when tripping out of the hole. When tripping in the hole the, trip tank should be used to ensure the correct mud displacement is taking place. Rig movement with a floating drilling rig makes it more difficult to recognise kick indicators while drilling or tripping. For this reason additional fluid volume detection equipment is installed in the mud pits to compensation for rig motion. It is recommended for floating drilling units that flow checks be performed on the trip tank with the hole fill pump circulating across the bell nipple to eliminate rig motion as much as possible. Situations that can mask a kick:•

Mud weight adjustments while drilling.

•

Mud transfers while drilling.

•

Partial lost circulation.

•

Solids control equipment and degassing mud.

•

Spills and leaks in surface equipment.

•

Drain back.

•

Pump start up and shut down.

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3-9


3.11 KICK BEHAVIOUR A Comparison Between Oil and Water Base Muds Due to high temperatures and pressure a small gas kick can turn into a serious well control problem with oil base muds. Solution gas can become dissolved and miscible. The reason for this is that the gas remains in solution until it reaches its bubble point. In the same way that gas in a disposable lighter remains in its liquid phase until the pressure is relieved. In fig 3.4a three barrels of mud have entered the wellbore at 10,000 ft, but we would see no pit gain while drilling until the gas has been circulated up to 2600 ft. The gas then expands rapidly and there is a real danger of blowing out sufficient mud to put the entire well underbalance. This problem is easier to detect in water based muds because the original volume of the gas will expand much earlier as the pressure above the gas is reduced (see fig. 3.4b). The problem in OBM's is that if a kick has entered the wellbore undetected it is impossible to know where the top of the gas is. For example if the drilling rate is say 80 SPM and the pump output is .117bbls per stroke then in an 8.5" hole section with 5" drillpipe the influx would travel 203 ft. for each minute that the kick is undetected. In extreme cases the gas could be 6000 - 7000ft. away from the surface without the driller realising anything is wrong. Under these conditions it may be prudent to count all drilling breaks as primary indicators. Stop drilling, shut off the pumps and close the well in. The gas can then be circulated through the choke in a safe manner utilising the first circulation of the drillers method. Some procedures advise that the gas should be circulated to 2500 ft. below the BOP before the well is shut in and the gas circulated through the choke. It may be the case that the bubble point is lower and unless this information is known, even though the first procedure may take a little longer, remember safety is always our main concern.

3 - 10

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GAS EXPANSION (UNCONTROLLED) (WELL OPEN)

If a gas bubble is allowed to expand without control of any kind it will eventually unload the well. With the well unloaded, kick sizes increasing, causing more unloading. This cycle of influx and unloading has caused the loss of many wells. Boyles Law is shortened version of equation for gas expansion e.g. P V = P V . 1 1 2 2 It generally states that if the volume of gas doubles, the pressure is reduced by half in the bubble. P1

=

V1

=

Hydrostatic Pressure (W/Gas bubble on bottom) =T.D Original Pit Gain

P2

=

Hydrostatic press at secondary depth

V2

=

Gas volume @ surface or at secondary depth

V2

=

P1V1 ––– P2

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GAS MIGRATION WHEN GAS IN SOLUTION (OIL BASE MUD)

Well Control problems can result in blowouts because of the solubility of certain gases in specific types of mud e.g. Methane dissolves in oil base mud, and H2S dissolves in water base mud. This fact makes it more difficult to detect a kick. A large gas influx entering the wellbore may change the pit level very little if the gas dissolves in the mud. The influx is then circulated up the wellbore in the mud column, until the hydrostatic pressure on top of the gas decreases to a certain point then the gas flashes or bubble point reached and gas comes out of solution. Detecting the kick by observing flow-line or mud pits can be very difficult until the kick is very close to surface and expands rapidly. Moreover, gas dispersed in well bore fluids does not migrate up the hole therefore a flo-check may not show.

3 - 12

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GAS MIGRATION (WELL SHUT IN) When a well is shut in on a kick that contains gas the gas will percolate or migrate up the hole even if the well is allowed to remain static. Gas migration can cause confusion during a well control operation, because it can be overlooked. Gas or Gas bubbles float or migrate up the hole because they are lighter than mud. When gas bubbles rise they expand or if they are not allowed to expand they cause an increase on all wellbore pressures and surface pressures. Therefore if a well is shut in for a long time, all pressures, wellbore surface etc. will increase causing lost circ. etc., if not relieved by allowing gas to expand. So lowering SIDPP to original value through choke and observing, keeping SIDPP at original value, will prevent this problem. All pressures will increase during migration of gas except pressure in actual bubble which is usually at formation pressure.

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3 - 13


Figure 3.4a - Oil Base Mud

Figure 3.4b - Water Base Mud

ASSUME: Three bbls of gas is swabbed into the hole during a connection (undetectable) 0 Surface Conditions 15 psi 70°F

2,500'

2,500' Depth

100% of Total Expansion

Depth

Bubble Point 1000' - 2000'

0 Surface Conditions 15 psi 70°F

5,000'

5,000'

Bottom Hole Conditions 7000 psi 250°F 10,000' 0 3 bbls Bbls

12 bbls Gas Volume

Detectable Pit Gain

6 bbls Gas Volume

Bottom Hole Conditions 7000 psi 250°F 10,000' 0 3 bbls Bbls 1,400

Solution gas will not migrate or expand until bubble point pressure is reached.

1,400

Gas in WBM will migrate and expand as pressure is reduced.

NOTE:The dissolving of gas into oil base mud does not hinder the detection of large volume kicks (5 bbls +), normal kick detection applies. After the well is shut in. Normal kick killing procedures apply.

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3.12 - WORKSHOP 3 1)

2)

3)

GAS cutting of the mud could be prevented by having a mud weight that gives a large over pressure. (a)

TRUE

(b)

FALSE

The affect on bottom hole pressure of gas cutting will be greatest: (a)

Initially when the gas enters into the mud.

(b)

When the gas cut mud nears the casing shoe.

(c)

When it gets near the surface.

Given the following data: Depth Shoe Mud

9850 ft TVD 5500 ft TVD 11 ppg (Assume this mud gives an overbalance of 150 psi.)

If the top 500 ft of this mud column is cut to 9 ppg and from 500 ft to 1300 ft the mud in the cut to 10.5 ppg, from 1300 ft to 1500 ft the mud is 10.8 ppg. If the rest of the system is uncut, what is the reduction in bottom hole pressure. Answer–––––––––––––––––––––

4)

If the gas cutting of the mud is at a constant level but shows significantly bigger peak levels when connections are made, this indicates: (a)

That formation permeability has changed.

(b)

That it must be high pressure gas from the formations.

(c)

That bottom hole pressure is increasing when the pumps are off.

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3 - 15


5)

6)

7)

8)

9)

Generally predictions are based on the fact that abnormally pressured formations are not as “dense” as normally pressured formations at the same depth. Is this statement: (a)

TRUE

(b)

FALSE

An increase in both the volume and size of cuttings at the shaker is an indication of overpressured formations: (a)

TRUE

(b)

FALSE

Drilling in a deep high pressure high temperature well with oil based muds. A small gas kick that goes into solution: (Select two answers) (a)

Will remain in solution until it gets to the surface.

(b)

Will come out of solution when it reaches a bubble point pressure.

(c)

Would be easier to detect in water based muds.

An increase in penetration rate of a drilling break can be caused: (a)

By an increase in formation porosity.

(b)

By an increase in permeability.

(c)

By an increase in formation pressure.

(d)

By a change in one OR all of the above.

Connection gas as opposed to background gas can be caused: (a)

3 - 16

Due to a temporary reduction in the overall mud pressure during a connection.

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(b)

Due to a temporary increase in the overall mud pressure during the connection.

(c)

By a reduction in the rate of penetration.

WORKSHOP 3 - ANSWERS

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3 - 17



B

2.

C

3.

75 psi Reduction 500ft x 9ppg x .052 500

= 234psi +

800ft x 10.5ppg x .052

= 437psi +

1300

200ft x 10.8ppg x .052

= 112psi +

1500

8350 x 11ppg x .052

= 4776psi 5559psi

9850

3 - 18

4.

B

5.

A

6.

A

7.

B&C

8.

D

9.

A

9850 x 11ppg x .052

= 5634 - 5559 = 75psi

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SECTION 4 :

SHUT-IN PROCEDURES Page

4. 0

Objectives

1

4. 1

Introduction to Shut-in Procedures on a Fixed Rig

1

Soft Shut-in Procedure While Drilling on a Fixed Rig

2

Soft Shut-In Procedure While Tripping on a Fixed Rig

2

Hard Shut-In Procedure While Drilling on a Fixed Rig

3

Fast Shut-In Procedure While Drilling on a Fixed Rig

4

Diverter Procedure While Drilling on a Fixed Rig

4

General Introduction for Shut-In Procedure on a Floating Rig

5

Soft Shut-In Procedure While Drilling on a Floating Rig

6

4. 9

The Hard Shut-In Procedure on a Floating Rig

7

4.10

The Fast Shut-In Procedure on a Floating Rig

8

4.11

Shallow Gas and Diverting Procedure on a Floating Rig

8

4. 2 4. 3 4. 4 4. 5 4. 6 4. 7 4. 8

4.12

Surface & Subsea BOP's While Wireline Logging 10

4.13

Extracts from API RP59

11

Workshop 4(a) - Surface

19

Workshop 4(b) - Subsea

23

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WELL CONTROL for the Rig-Site Drilling Team SECTION 4 : SHUT-IN PROCEDURES

SHUT-IN PROCEDURES 4.0 OBJECTIVES To cover the shut-in procedures and diverter procedures for a surface BOP. To cover A.P.I. recommendations for these procedures which includes advantages and disadvantages. To cover the shut-in procedures and diverter procedures for a subsea BOP. To cover A.P.I. recommendations for these procedures which includes advantages and disadvantages.

4.1 GENERAL INTRODUCTION TO SHUT-IN PROCEDURES ON A FIXED RIG Note: A fixed rig is defined as a drilling rig equipped with a surface BOP. Shut-in procedure should be agreed by contractor and operating company and posted on rig floor before drilling the well begins. When any positive indication of a kick is observed such as a sudden increase in flow or an increase in pit level, then the well should be shut in immediately without doing a flow check. If the increase in flow or pit gain is hard to detect then a flow check can be done to confirm the well is flowing. If surface hole is being drilled and the conductor pipe is not set in a competent formation and a shallow gas kick is taken then the gas should be diverted. This will be discussed at the end of this section. The procedures which follow are generalised suggestions and not necessarily applicable to any specific rig.

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4-1


4.2 SOFT SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG 1.

When any indications are observed, while drilling, that the well may be flowing, stop rotating the drill string, raise the drill string with pumps on until tool joint is above the drill floor.

2.

Stop pumps and check for flow, if positive:

3.

Open choke line HCR valve.

4.

Close BOP. 5.

Close choke. If the choke is not a positive closing choke then close a valve downstream of choke.

6.

Call supervisors and commence plotting a graph of shut in drill pipe pressure. Check pit volume gain.

7.

Refer to A.P.I. R.P. 59 section 3.8 for the advantages and disadvantages of the soft shut-in.

Note: Choke in open position while drilling.

4.3 SOFT SHUT-IN PROCEDURE WHILE TRIPPING ON A FIXED RIG

4-2

1.

If there is an indication of swabbing and the well flows during a flow check proceed as follows.

2.

Set the slips.

3.

Install full opening safety valve (Kelly cock).

4.

Close safety valve.

5.

Open choke line HCR valves.

6.

Close BOP.

7.

Close choke.

8.

Call supervisor and check pressures.

9.

Install inside blowout preventer (Gray valve or Non-Return Valve).

10.

Open safety valve.

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11.

Reduce annular preventer pressure and start stripping drill pipe in the hole. Note: Choke in open position while tripping.

With a swabbed kick there are four options: 1.

Strip back in hole.

2.

Perform a volumetric bleed.

3.

Bullhead kick back into formation.

4.

Perform off bottom kill then return to bottom and circulate well to desired mud weight.

4.4 HARD SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG 1.

When any indication is observed while drilling that the well maybe flowing, stop rotating the drill string, raise the drill string with pumps on until tool joint is above the drill floor.

2.


3.

Close annular or pipe rams.

4.


5.

Call supervisor and commence plotting a graph of shut in drill pipe pressure. Check pit volume gain.

6.

Refer to A.P.I. R.P. 59 sections 3:7 for advantages and disadvantages of the hard shut-in.

After the well has been shut in. In any shut-in procedure it is prudent to line up the annulus to the trip tank above the annular or rams. This will assist in double checking to see if they are leaking. Double check that the well is lined up through the choke manifold prior to circulating kick out.

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4-3


4.5 FAST SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG 1.

When any indication is observed while drilling that the well maybe flowing, stop rotating the drill string, raise the drill string with pumps on until tool joint is above the drill floor.

2.


3.


4.

Close Annular. 5.


Note: There are no A.P.I recommendations for the fast shut-in

4.6 DIVERTER PROCEDURE WHILE DRILLING ON A FIXED RIG 1.

Where shallow casing strings or conductor pipe are set, fracture gradients will be low. It may be impossible to close the BOP on a shallow gas kick without breaking down the formation at the shoe. If a shallow gas kick is taken while drilling top hole then the kick should be diverted. Drilling shallow sand too fast can result in large volumes of gas cut mud in the annulus and cause the well to flow, also fast drilling can load up the annulus increasing the mud density leading to lost circulation and if the level in annulus drops far enough then well may flow. When drilling top hole a diverter should be installed and it is good practice to leave the diverter installed until 13 3/8" casing has been run. An automatic diverter system should first:-

4-4

a)

Open an alternative flow path to overboard lines.

b)

Close shaker valve and trip tank valve.

c)

Close diverter annular around drill pipe.

d)

If there are two overboard lines then the upwind valve should be manually closed.

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2.

If any indication of flow is observed while drilling top hole, close diverter immediately as the gas will reach surface in a very short time and it is inadvisable to attempt a flow check.

3.

Suggested diverting procedure in the event of a shallow gas kick. a)

Maintain maximum pump rate and commence pumping kill mud if available.

b)

Space out so that the lower safety valve is above the drill floor.

c)

With diverter line open close shaker valve and diverter packer.

d)

Shut down all nonessential equipment, if there is an indication of gas on rig floor or cellar area then activate deluge systems.

e)

On jack-up and platform rigs monitor sea for evidence of gas breaking out around conductor.

f)

If mud reserves run out then continue pumping with sea-water.

g)

While drilling top hole a float should be run. This will prevent gas entering drill string if a kick is taken while making a connection. It will also stop backflow through the drill string on connections.

4.7 GENERAL INTRODUCTION FOR SHUT-IN PROCEDURE ON A FLOATING RIG Note: A floating rig is defined as a rig equipped with subsea BOP’s. Shut-in procedure should be agreed by contractor and operating company and posted on rig floor before drilling the well begins. When any positive indication of a kick is observed such as a sudden increase in flow or increase in pit level, then the well should be shut in immediately without doing a flow check. If the increase in flow or pit gain is hard to detect then flow check can be done to confirm the well is flowing. It maybe difficult to obtain an accurate flow check by observing flow line on rig floor or flow line at shaker due to rig movement.

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4-5


To obtain an accurate flow check: a)

Stop rotating, pick up and space out for hang off rams.

b)

Shut down rig pumps.

c)

Line up trip tank.

d)

Close shaker valve.

e)

Half fill trip tank with mud and perform a flow check.

If surface hole is being drilled and the conductor or surface casing is not set in a competent formation and a shallow gas kick is taken, then the kick should be diverted and not shut in. Diverting procedure will be discussed at the end of this section. The procedure which follow are generalised suggestions and not necessary applicable to any specific rig.

4.8 SOFT SHUT-IN PROCEDURE WHILE DRILLING ON A FLOATING RIG

4-6

1.

When any indication is observed while drilling that the well maybe flowing, stop rotating the drill string, raise drill string with pumps running and space out for hang off rams.

2.


3.

Open fail-safe valve, open the choke line.

4.

With compensator at mid-stroke, close annular.

5.

Close choke if the choke is not a positive closing choke then close a valve downstream of choke.

6.


7.

Close hang off rams with reduced pressure, reduce annular pressure, slack off and land drill string on rams. Increase manifold pressure to 1500 psi and open annular.

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8.

Close wedge locks and adjust compensator to support drill string weight to BOP plus 20,000 lbs.

Note: There will be pressure trapped between annular and rams. 9.

It has become accepted practice to the lower annular to minimise volume of gas trapped in BOP. With a stack set up of three sets of pipe rams and one set of shear rams, hang off rams would always be upper or middle pipe rams but never lower pipe rams. This is because if a kill or choke line washes out beneath the lower pipe rams it would be impossible to secure the wall.

10.

Refer to A.P.I. R.P 59 section 3:8 for advantages and disadvantages for the soft shut-in.

Note: Choke in open position while drilling.

4.9 THE HARD SHUT-IN PROCEDURE ON A FLOATING RIG 1.

When any indication is observed while drilling that the well maybe flowing, stop rotating the drill string, raise drill string with pumps running and space out for hang off rams.

2.


3.

With compensator at mid-stroke close annular or pipe rams.

4.

Open fail-safe valves on the choke line.

5.


6.

If rams have been closed then reduce manifold pressure, slack off on drill string and land tool joint on rams. Increase manifold pressure to 1500 psi close wedge locks, adjust compensator to support drill string weight to BOP plus 20,000 lbs.

7.

Refer to A.P.I. R.P. 59 section 3:7 for advantages and disadvantages of the hard shut-in.

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4-7


4.10 THE FAST SHUT-IN PROCEDURE ON A FLOATING RIG 1.

When any indication is observed while drilling that the well maybe flowing, stop rotating, raise drill string with pumps running and space out for hang off rams.

2.

Stop pump and check for flow, if positive:

3.

Open fail-safe valves on the choke line.

4.

With compensator at mid-stroke, close annular.

5.

Call supervisors and commence plotting a graph of shut in drill pipe pressure, check pit volume gain.

6.

Close hang off rams with reduced pressure, reduce annular pressure, slack off and land drill string on rams. Increase manifold pressure to 1500 psi open annular.

7.

Close wedgelocks and adjust compensator to support drill string weight to BOP plus 20,000 lbs.

Note: There will be pressure trapped between annular and rams. 8.

There are no A.P.I. recommendations for the fast shut-in.

4.11 SHALLOW GAS AND DIVERTING PROCEDURE ON A FLOATING RIG

4-8

1.

Shallow gas sand lenses are normally completely enveloped in mud stone and tend to be highly porous, permeable and relatively unconsolidated. These lenses maybe normally pressured, but if they are lying at an inclination they may be overpressured.

2.

Shallow gas kicks happen when drilling into a sand lens and are generally caused by loss of hydrostatic head due to one or a combination of the following. a)

Overloading the annulus with cuttings which may cause losses.

b)

Fast drilling leading to drilled gas unloading the annulus.

c)

Improper hole fill while tripping if a riser has been run.

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3.

4.

The following are the recommended procedures for drilling 36" and 24" hole from a floating rig if there is a risk of shallow gas. a)

Drill a pilot hole prior to drilling 24" hole.

b)

Drill with returns to sea-bed.

c)

Restrict penetration rate to avoid overloading annulus or having an excess of drilled gas in annulus.

Precautions to take while drilling top hole.

5.

6.

a)

If possible have camera on sea-bed observing for any sign of gas.

b)

Have a crew member observing surface of sea.

c)

A procedure for moving the rig off location must be in place and this procedure should be practised prior to spudding the well.

d)

A reserve of weighted mud of twice hole volume should be mixed prior to spudding well.

e)

A float should always be run in drill string.

Suggested action to take if a shallow gas kick occurs while taking returns to sea-bed. a)

Attempt to control the well by pumping sea water or mud.

b)

If gas flow is endangering personnel or rig, attempt to drop drill string.

c)

Move rig to a safe position up wind of gas plume.

Suggested action to take if a riser and connector has been run and a shallow gas kick has been taken. a)

It is not recommended to divert as any solids in the gas influx will quickly erode overboard lines.

b)

Drop the drill string.

c)

Unlatch the connector with an overpull on riser tensioner lines.

d)

Move rig to a safe position outside and upwind of gas plume while slacking off on guide lines.

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4-9


4.12 SURFACE & SUBSEA BOP’S WHILE WIRELINE LOGGING -

Direct the wireline loggers to cease operations and close the well on the upper annular.

-

Open kill line valves and begin to record shut in pressure and pit gain.

-

Pass word to the OIL COMPANY REPRESENTATIVE and SENIOR DRILLING CONTRACTOR REPRESENTATIVE of the well condition.

-

Decide on kill programme.

Note: If at all possible the wireline should be pulled or stripped out of the hole. If the line needs to be cut and dropped, a surface hydraulic cable cutter should be used. The shear rams should be considered as a last resort and used only if the annular(s) fail to secure the well.

4 - 10

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4.13 EXTRACTS FROM API RP59 CLOSING IN KICKS 3.6 Soft Close-in Procedure. For a soft close-in, a choke is left open at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system, with the exception of one choke line valve located near the blowout preventer. When the soft close-in procedure is selected for closing in a well the: 1) choke line valve is opened, 2) blowout preventer is closed, and 3) choke is closed. This procedure allows the choke to be closed in such a manner to permit sensitive control and monitoring of casing pressure buildup during closure. This is especially important if formation fracturing and broaching to the surface is likely to occur if the well is closed in without regard to the possibility of excessive initial closedin casing pressure. 3.7 Hard Close-in Procedure. For a hard close-in, the chokes remain closed at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system with the exception of the choke(s) itself and one choke line valve located near the blowout preventer stack. When the hard close-in procedure is selected for closing in a well, the blowout preventer is closed. If the casing pressure cannot be measured at the wellhead, the choke line valve is opened with the choke or adjacent high pressure valve remaining closed so that pressure can be measured at the choke manifold. This procedure allows the well to be closed in the shortest possible time, thereby minimising the amount of additional influx of kicking fluid to enter the wellbore. Use of the hard close-in procedure is limited to well conditions in which the maximum allowable casing pressure is greater than the anticipated initial close in pressure and a well fracture would not be expected to broach to the surface on initial closure. 3.8 Soft Close-in Versus Hard Close-in Procedure. The soft close-in procedure provides a means of monitoring casing pressure and a more sensitive control of casing pressure buildup during closure than will be experienced using the hard close-in procedure. If the initial closed-in casing pressure is likely to exceed the maximum allowable casing pressure, the soft close-in procedure permits initiation of a low choke pressure procedure or other alternate procedures before maximum allowable casing pressure is reached. In this situation, the soft close-in procedure has a distinct advantage over the hard close-in procedure. The major disadvantage of the soft close-in procedure is that the additional time involved in opening the choke line valve and closing the choke will allow additional influx into the wellbore. This procedure will result in a larger kick volume and potentially higher casing pressure than obtained if the hard close-in procedure is used while circulating out the kick. The hard close-in procedure is somewhat less complicated, can be performed by one man working on the rig floor, and is more likely to be performed without inadvertent delays in closure than the soft closein procedure.

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4 - 11


3.9 Stabilised Pressures. When a kick is detected, the well should be closed in as quickly as possible to minimise kick influx volume. Figure 3.3 shows a schematic diagram of a well shut in on a kick. In this well, a 20-barrel gas influx occurs when drilling at 10,000 feet with a 10.0 Ib/gal drilling fluid. The stabilised closed-in pressures are 500 psi on the drill pipe and 640 psi on the casing or annulus gauge. Figure 3.4 illustrates various pressures in the wellbore. To understand how the various pressures interact, it is necessary to isolate and identify each one. The drill pipe gauge pressure plus the hydrostatic pressure of the drilling fluid equals the formation pressure. The same pressure balance can be made for the annulus, i.e., casing gauge pressure plus the hydrostatic pressure of the annulus drilling fluid plus the hydrostatic pressure of the influx equals the formation pressure. 500 PSI Figure 3.5 illustrates an example of a 10,000 DRILL foot closed-in well with 10.0 Ib/gal drilling 640 PSI PIPE fluid and a small volume of gas at bottom. CASING When the gas rises to 5000 feet without expansion or temperature change, the bottom-hole pressure rises to 7800 psi, which is equivalent to a 15.0 Ib/gal drilling fluid column. When the gas reaches the surface, bottom-hole pressure is 10,400 psi, which is equivalent to a 20.0 Ib/gal drilling fluid column. At 5000 feet the borehole pressure is equivalent to a 10 LB/GAL DRILLING FLUID 30.0 Ib/gal drilling fluid column to that depth. Such 10 LB/GAL excessive pressure should DRILLING FLUID be avoided whether gas rises through a static drilling fluid column or is circulated out by allowing the gas to expand as it rises. This also requires that the pits be allowed to gain 20 BBL GAS ENTRY volume. If a gas bubble is permitted to rise in a wellbore BOTTOM-HOLE PRESSURE without expanding, the gas = 5700 PSI pressure will remain constant. FORMATION PRESSURE The reduced hydrostatic head 10,000 FT = 5700 PSI above the gas column must be overcome by increased WELL CLOSED IN ON A KICK surface pressure on the casing: in turn this increased pressure results in a higher bottom-hole pressure.

4 - 12

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ANNULUS

DRILL PIPE

INITIAL SURFACE PRESSURE

FINAL

0 PSI

2600 PSI

5200 PSI

0 FT

GAS 5200 PSS

640 PSI

500 PSI

DRILLING FLUID COLUMN PRESSURE

5000 FT

DRILLING FLUID COLUMN PRESSURE

4980 PSI

5200 PSI

80 PSI

5700 PSI

5700 PSI

GAS HYDROSTATIC PRESSURE

10000 FT

5700 PSI

DRILLING FLUID 5200 PSS

GAS 5200 PSS

DRILLING FLUID 5200 PSS

GAS 5200 PSS

BOTTOM-HOLE PRESSURE

= 5200 PSI

= 7800 PSI

EQUIVALENT DRILLING FLUID DENSITY

= 10.0 LB/GAL

= 15.0 LB/GAL = 20.0 LB/GAL

FORMATION PRESSURE

=10400 PSI

FIG 3.5

CLOSED-IN WELLBORE PRESSURE WITH TIME

FIG 3.4

WELL CLOSED IN ON A KICK

3.10 Closed-in Drill Pipe Pressure. Formation pressure near the wellbore is reduced during flow. When the well is closed in, the borehole pressure will rise until equal to formation pressure. As the drill pipe (and annulus) is in communication, the drill pipe pressure will also rise and stabilize. The drill pipe pressure at this time indicates the amount to increase the drilling fluid density. If the well is not circulated, the gas will slowly rise and increase both wellbore and drill pipe pressures. Drill pipe pressures read after the initial stabilized reading will indicate excessive drilling fluid density increase. To avoid excess wellbore pressures, the choke should be used to bleed drilling fluid from the casing and maintain the initial shut-in drill pipe pressure. These conditions are illustrated in Figure 3.6. To determine the closed-in drill pipe pressure when a back-pressure valve is in the drill string, pressure should be increased slowly using the smallest pump available to determine the pressure at which the back-pressure valve opens. If casing pressure is seen to rise while pumping on the drill pipe, pumping should be stopped and the increase in casing pressure subtracted from drill pipe pressure. INCREASE DUE TO RISE OF GAS

DRILL PIPE PRESSURE PSI

DESIRED VALUE

FIG 3.6

CLOSED-IN DRILL PIPE PRESSURE

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TIME

4 - 13


FORMATION INTEGRITY TESTS 3.11 Leak-off Test. A leak-off test is made to determine the pressure at which a formation will begin to fracture. Leak-off tests are usually run after drilling a short distance below the surface casing shoe. These tests may also be made on other casing strings. A leak-off test is performed by pumping drilling fluid into the wellbore at a slow rate (typically one-half barrel per minute), with blowout preventers closed and carefully plotting the resulting pressure versus the total volume pumped. The pressure at which the plotted curve begins to flatten. i.e., when the pressure increases a smaller amount for a volume pumped, is the surface leak-off pressure. The pump should be stopped immediately. This pressure plus the hydrostatic pressure of the drilling fluid is the formation fracture pressure. Formation fracture pressure (psi) = Leak-off pressure (psi) + [.052 x Drilling fluid density (Ib/gal)] x Casing TVD (ft).

It is useful to calculate the formation fracture gradient as equivalent or fracture drilling fluid density. Fracture drilling fluid density (Ib/gal) = Leak-off pressure ––––––––––––––––––– .052 x Casing TVD (ft)

+

Drilling fluid density in use during test (Ib/gal).

Fracture pressure is the maximum surface pressure that can be applied to a casing that is full of drilling fluid without fracturing the formation. Fracture pressure is calculated as follows: Fracture pressure (psi) = .052 x Casing TVD (ft) x [Fracture drilling fluid density (Ib/gal) - Present drilling fluid density (lb/gal)].

3.12 Formation Competency Test. A formation competency test is made to determine if a wellbore will support drilling fluid of a higher density which may be required at some future time during the well drilling and completion operations. The formation competency test is performed by pumping drilling fluid into the wellbore at a slow rate (typically one-half barrel per minute) with blowout preventers closed. Pumping into the wellbore should be continued until reaching the predetermined test pressure as calculated below: Test pressure (psi) = .052 x Casing TVD (ft) x [Required test drilling fluid density b/gal) - drilling fluid density currently in use (Ib/gal)].

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CREW DRILLS The proficiency with which drilling crews react to well control situations and follow correct control procedures can be enhanced by repetitive drills. When the desired proficiency is attained, periodic drills should be continued to maintain performance. The following drills, frequency, and proficiency levels are considered desirable: A. Pit Drill. Without prior warning and during a routine operation, the rig supervisor should simulate a gain in pit drilling fluid volume by raising a float sufficiently to cause an alarm to be activated. If automatic equipment is not available, the drills may be signalled by word of mouth. This, of course, diminishes the surprise element, but the training is still effective. The drilling crew should immediately initiate one of the four procedures discussed in Paragraph B depending on the operation at the time of the drill. A pit drill is terminated when the crew has completed the steps up to, but not including, closing the blowout preventers (Crews must be advised that this is a pit drill, otherwise they should proceed with the complete blowout preventer drill). The supervisor initiating the drill should record response time. Crew response time should be one minute or less. B. Blowout Preventer Drill. This drill includes all steps of the pit drill (refer to Paragraph A) but is continued through all the steps of closing in the well as outlined below. This drill should be repeated on a daily basis until each crew can close in the well within a span of two minutes. Thereafter the drill should be repeated weekly to maintain proficiency. 1. On-bottom Drill. a. Signal given. b. Stop rotary. c. Raise kelly tool joint above the rotary, while sounding the alarm. d. Stop pump. e. Check for well flow. The on-bottom drill should be carried only to the point of driller recognition, signalled by raising the kelly and pump shutdown. This is to avoid the danger of stuck pipe.

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2. Tripping Drill Pipe Drill a. Signal given. b. Position the upper tool job above rotary table and set slips. c. Stab full-open valve on drill pipe. d. Close drill pipe safety valve. e. Close blowout preventer. Drills while tripping drill pipe should be performed after the bit is up in the casing. A full opening safety valve for each size and type connection in the string must be open and on the floor ready for use. Safety valves must be clearly identified as to size and connection to avoid confusion and lost time when stabbing. 3. Drill with Drill Collars in the Preventer. a. Signal given b. Position the upper drill collar in rotary table and set slips. c. Stab full-open safety valve made up on one joint of drill pipe with change-over sub onto collars. NOTE: Preparation for this operation must be made in advance. Prior to reaching the drill collars when pulling out of the hole, a drill pipe to drill collar change-over sub must be placed on a single joint of drill pipe. The full open safety valve is then made on the top of the joint of drill pipe. d. Lower collars with joint of drill pipe into the hole. e. Close the drill pipe safety valve. f. Close the pipe rams above drill pipe tool joint. Flows that occur with drill collars in the preventers will generally be quite rapid since they are usually the result of expansion of a gas bubble that is quite close to the surface. The joint of drill pipe picked up with the elevators will usually be easier to stab and make up than a safety valve alone. Under actual kick conditions (other than drill) if only one stand of drill collars remained in the hole it would probably be faster to simply pull that last stand and close the blind rams.

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4. Out of the Hole Drill. a. Signal given. b. Close blind rams.

C. Stripping Drill. The performance of a stripping drill by at least one crew on each well should be considered. This drill can be conveniently performed after casing is set and before drilling out cement. With drill pipe in the hole a blowout preventer should be closed and the desired pressure trapped. Each crew member should be assigned a specific position. Following an acceptable procedure, the crew should strip sufficient pipe into the hole to establish the workability of the equipment and to allow each crew member to learn to perform assignments. In addition to establishing equipment reliability, this will permit the training of at least one crew on each well. Over a period of time, all crews should become proficient in stripping operations. Stripping drills are not recommended for operations involving subsea blowout preventer stacks. D. Choke Drill. Choke drills should be performed before drilling out surface casing and each subsequent casing string. With pressure trapped below a closed preventer, the choke should be used to control casing pressure while pumping down the drill pipe at a prescribed rate. This drill will establish equipment performance and allow the crew to gain proficiency in choke operation. It is desirable to discharge into a trip tank to accurately monitor flow rates for correlation with choke opening, pump rates, and pressure drops in the circulating system and across the choke. This is particularly important for subsea blowout preventer stacks in deep water, which may have significant circulating pressure losses in the choke lines. E. Hang-off Drill (Subsea Blowout Preventers Only) Following prescribed procedures, the crew should place the drill string in position for hang-off. One hang-off should be made before drilling out of surface pipe to ensure that all necessary equipment is on hand and in working condition. Actual hang-off will not normally be performed on subsequent drills. This drill can be conveniently performed in conjunction with the pit drill.

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TRIP TANKS A trip tank is a low-volume, calibrated tank which can be isolated from the remainder of the surface drilling fluid system and used to accurately monitor the amount of fluid going into or coming from the well. A trip tank may be of any shape provided that it is calibrated accurately and a means is provided for reading the volume contained in the tank at any liquid level. The readout may be direct or remote, preferably both. The size of the tank and readout arrangement should be such that volume changes in the order of one-half barrel can be easily detected. Tanks containing two compartments with monitoring arrangements in each compartment are preferred as this facilitates removing or adding drilling fluid without interrupting rig operations. The primary use of the trip tank is to measure the amount of drilling fluid required to fill the hole while pulling pipe to determine if the drilling fluid volume matches pipe displacement. Other uses of the trip tank include measuring drilling fluid or water volume into the annulus when returns are lost, monitoring the hole while logging or following cement job, calibrating drilling fluid pumps, etc. The trip tank is also used to measure the volume of drilling fluid bled from or pumped into the well as pipe is stripped into or out of the well. TRIP BOOK A tally should be maintained showing the volume of drilling fluid required to fill the hole after pulling the specified number of stands along with the cumulative volume. It is important to keep this record in a "trip book" so that each trip may be compared with previous trips for anomalous behaviour, rather than to rely only on comparison with theoretical displacement volumes. A similar record is made of drilling fluid returns while running pipe in the hole.

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4.14 - WORKSHOP 4(a) - Surface

ANNULAR PREVENTER

Note: The well will be killed using the left hand automatic choke.

Remotely operated choke - left hand SHEAR RAM To mud/gas separators, pits and diverter lines

P

15

Manual Adjustable Choke

8 9 5" PIPE RAM

To pit

HCR VALVE

HCR VALVE

CHOKE 7 LINE

Bleed line

DRILL SPOOL 1

2

11 3

12

4 10 13

5" PIPE RAM To mud/gas separators, pits and diverter lines

P

14 Remotely operated choke - right hand

CASING HEAD 5

6

P

= Positive Closing Choke

Questions 1-4 refer to the diagram above. The valves shown are numbered 1 to 15.

1.

If all of the above valves were closed, indicate below those valves that should be in the open position if the Manifold is lined up to suit a Soft Shut-in (excluding choke). Answer:

2.

Referring to the above question indicate the position of the chokes, when lined up for a Soft Shut-in . a. b. c.

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Left hand remote choke Manual adjustable choke Right hand remote choke

Opened Opened Opened

Closed Closed Closed

4 - 19


3.

Indicate the position of the chokes, when lined up for a Fast Shut-in . a. b. c.

4.




Indicate the position of the chokes, when lined up for a Hard Shut-in . a. b. c.




If an indication of a Kick while Drilling occurs, or if the Well flows while Tripping, then the well must be closed-In. (A Kelly is being used) The following is a list of possible Actions that could or could not be taken when shutting the well in.

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17.

Pick up and space out Stop Rotating Set Slips Open HCR valve Close HCR valve Install Safety Valve(FOSV) Open Safety Valve Close Safety Valve Open Ram Preventer Close Ram Preventer Open Annular Preventer Close Annular Preventer Stop pumping Install Inside B.O.P (Grey Valve) Open Choke Close Choke Record Data

For questions 5 to 8 refer to the list shown above.

5.

Select the correct sequence of actions which should be taken if a well kicks while drilling and the Soft Shut-in is to be used. Answer:

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6.

Select the correct sequence of actions which should be taken if a well kicks while drilling and the Fast shut-in is to be used. Answer:

7.

Select the correct sequence of actions which should be taken if a well kicks while drilling and the Hard shut-in is to be used. Answer:

8.

If a well flow while Tripping, select the correct sequence of actions which should be taken if the Fast shut-in is to be used. Answer:

9.

Secondary well control could be defined as initially; a. b.

10.

Prior to Stripping back to bottom, and assuming there is no float valve in the string, the equipment made up on top of the string would generally be; a. b. c. d. e. f.

11.

Controlling formation fluids with the pressure of the mud column, in a static or dynamic condition. Controlling formation fluids with the pressure of the mud column and the well closed in.

A Safety valve (Kelly cock) in the closed position. An Inside Blow-Out Preventer (Grey valve). An I.B.O.P valve on top of a opened Safety Valve. A Safety valve closed with an IBOP valve below it. A closed Regan "Fast Shut-off valve". An I.B.O.P. valve on top of an opened Regan "Fast Shut-off valve".

If a well starts to Flow due to Gas at shallow levels, the safest action would be: (Select three answers) a. b. c. d. e. f.

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Shut the Well in as fast as possible, use a ram preventer. Shut the diverter and then open the vent line and close the flow line. Open the vent line, close the flow line and then close the diverter. Have all nonessential personnel removed from the rig. Pump into the well at the fastest rate. Line up the returns to go through the Poor-Boy Degasser.

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WORKSHOP 4(a) - Answers 1.

4 - 22

The valves which should be in the open position: numbers: 2, 3, 7, 8 and 15.

ref ch 6-43

2.

Left hand remote choke- opened Manual Adjustable choke- closed Right hand remote choke- closed

3.

Left hand remote choke- closed Manual Adjustable choke- closed Right hand remote choke- closed

4.

As Q 3. All chokes Closed

5.

2, 1, 13, 4, 12, 16 and 17.

ref. ch 4-2

6.

2, 1, 13, 4, 12 and 17

ref. ch 4-5

7.

2, 1, 13, 10 or 12, 4 and 17

ref. ch 4-3

8.

1, 3, 6, 8, 4, 12, 14, 7 and 17

ref. ch 5-29

9.

b.

ref. ch 1-1

10.

c.

ref. ch 5-29

11.

c. d. and e.

ref. ch 4-4

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WORKSHOP 4(b) - Subsea To port - Blow-down line flare line

From C&K manifold 4” pipe

Vent to top of derrick

to mud-gas separator

10” Vent

28

Blow-down line To starboard flare line

27

26

36” diameter separator Mud-gas separator

31

29

22 30

To shale shaker

23

Manual choke

L/hand remote choke 21 20

24

18 14

16

19

25

R/hand remote choke

17

13

2 15

1

11 12 10

3

5

4

9

6

To shale shaker

Kill line

7

To cement unit mud pumps

8

Choke line

DECK LEVEL

SEA LEVEL

Flex joint

NOTE: Right hand auto-choke will be used during well killing operations. The upper pipe rams will be used during well kill operations.

Annular Preventer

H-4 Connector

Kill line

Choke line

Annular Preventer

REMOTELY ACTUATED VALVES F5

F6

F7

F8

Shear Rams 5” Rams Variable Rams

F1

F2

F3

F4

5” Rams

SEA FLOOR

H-4 Connector

Questions 1-4 refer to the stack and manifold diagram. The valves shown in the diagram are on the choke and kill line at the stack numbered F1 to F8. The valves on the manifold are numbered 1 to 31.

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1.

If all of the above valves were closed, indicate below those valves that should be in the open position if the Manifold is lined up to suit a Soft Shut-in while drilling. Answer:

2.

Referring to the above question indicate the position of the chokes, when lined up for a Soft Shut-in . a. b. c.

3.



Indicate the position of the chokes, when lined up for a Fast Shut-in . a. b. c.

4.





Indicate the position of the chokes, when lined up for a Hard Shut-in . a. b. c.




If an indication of a Kick while Drilling occurs, or if the Well flows while Tripping, then the well must be closed-In. (A Kelly is being used) The following is a list of possible Actions that could or could not be taken when shutting the well in. 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16.

4 - 24

Pick up and space out Stop Rotating Set Slips Open Fail-safe valves Close Fail-safe valves Close Ram preventer Open Ram preventer Close Upper Annular Close Lower Annular Open Annular Open Choke Close Choke Stop pumping Set compensator to mid stroke Hang Off Record Data

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For questions 5 to 7 refer to the list shown above. 5.

Select the correct sequence of actions which should be taken if a well kicks while drilling and the Soft Shut-in is to be used. Answer:

6.

Select the correct sequence of actions which should be taken if a well kicks while drilling and the Fast shut-in is to be used. Answer:

7.

Select the correct sequence of actions which should be taken if a well kicks while drilling and the Hard shut-in is to be used. Answer:

8.

Having information about tides and rig heave on a floating rig is important for many reasons, particularly if a well has to be shut in. From the following select the most important reason for this. a. b. c. d.

9.

Some sensible precautions that could be taken while drilling top if there is any risk of shallow gas would be: (There is more than 1 answer) a. b. c. d. e.

10.

To know the exact measured depth from the bit to the rig floor. To know where the tool joints are in relation to the ram that will be used. To be able to make necessary adjustments to the riser tensioners To reduce the risk of collapsing the riser.

Monitor sea bed returns and observe surface of sea. Drill pilot hole Restrict penetration rate Close the well in at the first sign of flow All of the above.

Drilling for the 20 inch casing is generally done without a riser. this is because: a. b. c. d.

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It is much easier to detect any flow or pit changes. It is easier to control bottom hole pressure It is easier to move the rig off location in an emergency It is easier to close the well in.

4 - 25


WORKSHOP 4(b) - Answers

4 - 26

1.

The valves which should be in the open position: numbers: 8, 9, 10, 11, 12, 25, 26, 27 and 30

2.

Left hand remote choke- closed Manual Adjustable choke- closed Right hand remote choke- opened

3.

Left hand remote choke- closed Manual Adjustable choke- closed Right hand remote choke- closed

4.

As Q 3. All chokes Closed

5.

2, 1, 13, 4, 8, 12, 6, 15, 14, 10 and 16

6.

2, 1, 13, 4, 8, 6, 15, 14, 10 and 16

7.

2, 1, 13, 8, 4, 6, 15, 14, 10 and 16

8.

b.

9.

a, b and c

10.

c.

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SECTION 5 :

METHODS OF WELL CONTROL Page

5. 0

Objectives

1

5. 1

Kill Methods General

1

5. 2

Constant Bottom Hole Pressure Kill Methods

4

5. 3

The Driller's Method

5

5. 4

The Wait and Weight Method

13

5. 5

Volumetric Well Control

17

5. 6

Volumetric Stripping

23

5. 7

Edited Extract From API RP53

28

5. 8

Removal of Gas Trapped in BOP's

30

5. 9

Kick Detection and Well Control Problems on Deviated and Horizontal Wells

34

5.10

Kick Tolerance

42

5.11

Workshop 5

49

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WELL CONTROL for the Rig-Site Drilling Team SECTION 5 : METHODS OF WELL CONTROL

METHODS OF WELL CONTROL 5.0 OBJECTIVES To cover the methods of well control for fixed rigs, to cover the special considerations for subsea rigs and to look at step down graphs for deviated and horizontal wells.

5.1 KILL METHODS GENERAL The objective of the various kill methods is to circulate out any invading fluid and circulate a satisfactory weight of kill mud into the well without allowing further fluid into the hole. Ideally this should be done with the minimum of damage to the well. If this can be done, then once the kill mud has been fully circulated around the well, it is possible to open up the well and restart normal operations. Generally, a kill mud which just provides hydrostatic balance for formation pressure is circulated. This allows approximately constant bottom hole pressure which is slightly greater than formation pressure to be maintained as the kill circulation proceeds because of the additional small circulating friction pressure loss. After circulation, the well is opened up again and the mud weight may be further increased to provide a safety or trip margin.

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5-1


BALANCE OF PRESSURES Once the well is shut-in providing nothing has broken down, the pressures in the well will be in balance. What is lacking in hydrostatic head of fluid in the well is now being made up by surface applied pressure on the annulus and on the drill pipe. Providing the bit is on bottom and the string is full with a known mud density this allows us to determine what the formation pressure is and hence what kill mud weight is required to achieve balance. On the drill pipe side of the U-tube. (Figure 5.1): Formation Pressure = [Hydrostatic Pressure of Mud in Drill pipe] + [Shut-in Drill Pipe Pressure SIDPP] On the casing side of the U-tube: Formation = Pressure

Hydrostatic Pressure + of Mud in Annulus

Hydrostatic Pressure + Shut-in Casing of Influx Pressure

The mixture of mud and formation fluid in the annulus makes it impossible to determine formation pressure using the casing information. The drill pipe, however, is full of clean mud of known weight and can be used as a “barometer’ of what is happening downhole. PF

=

Head of Mud In Drill pipe +

SIDPP

We require the mud to produce a hydrostatic pressure equal to the formation pressure over a length equal to the true vertical depth of the hole. This can be expressed as a gradient, and converted to any desired mud weight unit; in this case ppg. The kill mud weight required could also be described as the original mud weight increased by an amount which will provide a hydrostatic pressure equal to the amount of the drill pipe shut-in pressure over the vertical length of the hole. Kill Mud Weight (ppg) =

SIDPP (psi) Original Mud + –––––––––––––––––– ÷ 0.052 Weight (ppg) True Vertical Depth (ft)

[

]

Once the formation pressure is known, the mud weight required to balance, or ‘kill’, it can be calculated, since:Kill Mud Weight (ppg)

5-2

=

Formation Pressure (psi) ––––––––––––––––––– ÷ 0.052 True Vertical Depth (ft)

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Figure 5.1 ANNULUS

DRILL PIPE

CASING PRESSURE

DRILL PIPE PRESSURE

1220 psi

800 psi

MUD HYDROSTATIC PRESSURE IN THE DRILL PIPE

MUD HYDROSTATIC PRESSURE IN THE ANNULUS

8613 psi

9100 psi

67 psi

TOTAL PRESSURE ACTING DOWN (9100 + 800 = 9900 psi)

9900 psi

9900 psi

9900 psi

TOTAL PRESSURE ACTING DOWN (8613 + 1220 + 67 =9900 psi)

FORMATION PRESSURE

9900 psi

9900 psi Drill Pipe: SIDPP + Hydrostatic Pressure of Mud = Formation Pressure Annulus: SICP + Hydrostatic Pressure of Mud + Hydrostatic Pressure of Influx = Formation Pressure

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5-3


5.2 CONSTANT BOTTOM HOLE PRESSURE KILL METHODS There are three ‘constant bottom-hole pressure’ kill methods in common use today which are: •

Driller’s Method

•

Wait & Weight Method (also known as the ‘Engineer’s Method’)

•

Concurrent Method

These three techniques are very similar in principle, and differ only in respect of when kill mud is pumped down. In the Driller’s Method, the kill is split into two circulations. During the first, the kick fluid is circulated without changing the mud weight; once the kick is out, the mud is weighted up and pumped around the well on the second circulation. The Wait & Weight method achieves both of these operations simultaneously. Kill mud is prepared before starting the kill, and the kick fluid is circulated out while this mud is circulated into the well. In the Concurrent method, a compromise is adopted between these two methods. The kick fluid is circulated out while the mud being circulated in, is weighted up in stages, towards the kill weight.

5-4

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5.3 THE DRILLER'S METHOD In the Driller’s Method, the kick is circulated out of the hole using the existing mud weight. The mud weight is then raised to the required level and circulated around the well. Two complete circulations are thus required, as a minimum, for this method. Since it deals separately with the removal of the kick and the addition of kill weight mud, it is generally considered to be the simplest of well control methods, and it requires least arithmetic. However, this results, in the well being circulated under pressure for a relatively long time, possibly the longest of the three methods, with an increased possibility of choke problems. Also, the annular pressures produced during the first circulation are higher than produced with any other method. CAUTION: because very high annular pressure may arise when killing a gas kick with this method, care should be taken. Annular pressure will be at a maximum immediately before gas arrives at surface, and casing burst pressure limitations may be critical. This method is most used on small land rigs where the Driller may have little help and limited equipment. It is also used on highly deviated and horizontal wells, where the influx is likely to be a swabbed kick. In addition the simplicity of the Driller’s Method makes it useful when only limited information is available about the well conditions. To summarise: FIRST CIRCULATION: Pump the kick out of the well, using existing mud weight. SECOND CIRCULATION: Pump kill weight mud around the well. Advantages of Driller’s Method: • • •

Minimum Arithmetic Minimum Waiting Around Time - can start kill at once Minimum Information Required

Disadvantages of Driller’s Method: • • •

Highest Annular Pressure Produced Maximum Well Under Pressure Time Longest ‘On-choke’ Time

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5-5


Procedure for Driller’s Method (See Figure 5.2) 1.

The well is closed in and the information recorded.

FIRST CIRCULATION 2.

If a slow circulating rate pressure, PSCR, has been taken, then calculate the pressure required on the drill pipe for the first circulation of the well.

This is: or:

Initial Circulation = Slow Circulation Rate + Shut-in Drill pipe Pressure Pressure Pressure ICP = PSCR + SIDPP

3.

Open the choke about one quarter, start the pump and break circulation; then bring the pump up to the KILL RATE.

4.

While the Driller is bringing the pump up to the KILL RATE, the choke operator should operate the choke so as to keep the casing pressure at or near the closed in casing pressure reading.

5.

Once the pump is up to the KILL RATE, the choke operator should transfer his attention to the drill pipe pressure gauge and adjust the choke to maintain the INITIAL CIRCULATING PRESSURE on the drill pipe pressure gauge.

6.

The INITIAL CIRCULATING PRESSURE is held constant on the drill pipe pressure gauge by adjusting the choke throughout the whole of the first circulation, until all of the kick fluid has been circulated out of the well. The pump rate must also be held constant at the KILL RATE throughout this period.

7.

Once the kick is out of the hole, shut the well in and mix up the kill mud weight required.

Kill Weight Mud (ppg) =

Original Mud Weight +

(

SIDPP ––––––––––––––– T.V.D. x 0.052

)

NOTE 1: This is a kill weight mud to balance formation pressure. It is the lowest possible mud weight which will ‘kill’ the well. Once the well is dead, it will be necessary to increase the mud weight further to provide a trip margin. NOTE 2: Some operators prefer to continue circulating the well while kill weight mud is being mixed. There is no theoretical reason why this should not be done, though it does result in further wear and tear on equipment under pressure - in particular the choke. 5-6

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DRILLPIPE PRESSURE DROPPING

SIDPP

KILL WEIGHT MUD

D

A

GAS

CASING PRESSURE STEADY

SICP

Drill pipe pressure dropping (from I.C.P to F.C.P. as Kill Mud goes to bit )

CIRCULATING KILL MUD IN

DRILLER’S METHOD

Before start of first circulation

Gas Kick

KICK SHUT IN

DRILLER’S METHOD

INITIAL CIRCULATING PRESSURE

E F.C.P.

ORIGINAL WEIGHT MUD

B

KILL MUD

GAS EXPANDING

CASING PRESSURE BEING REDUCED

CASING PRESSURE RISING

Choke being steadily opened to keep F.C.P. on drill pipe, hence Casing Pressure reducing

KILL MUD COMING UP ANNULUS

DRILLER’S METHOD

F

Expanding gas is pushing more mud out of annulus, so Casing Pressure rising to compensate and KEEP CONSTANT BOTTOM HOLE PRESSURE

CIRCULATING KICK OUT

DRILLER’S METHOD

C

0 psi

SIDPP

0 psi

CASING PRESSURE = SIDPP

Well clean up may take some time - small residual pressure on the casing is thus likely

Shut in - kill mud all round well

WELL KILLED

Original weight mud all around well

Well closed in

FIRST CIRCULATION COMPLETE

DRILLER’S METHOD


Figure 5.2

5-7


SECOND CIRCULATION 8.

Once the kill mud is ready, open the choke about one quarter, start the pump and break circulation. Then bring the pump up to the kill rate.

9.

While the Driller is bringing the pump up to the kill rate, the choke operator should operate the choke so as to keep the casing pressure steady at the same pressure as when closed in.

10.

While the drill pipe is being filled with heavy mud there are two options for keeping B.H.P. constant, either keep the casing pressure constant or make out a graph going from I.C.P. to F.C.P.

NOTE: If the influx was gas and all the gas was not removed in first circulation, the first option of keeping casing pressure constant could lead to higher annular pressures. The drill pipe pressure will go down as the drill pipe is being slugged with the heavier mud. In practice, if all the kick was properly removed in the first circulation, the choke should not need to be touched once the pumps are steady at the Kill Rate, until kill mud reaches the bit. Once the kill mud reaches the bit, the pressure held on the drill pipe is just that required to circulate the kill mud around the well. This is the slow circulating rate pressure, increased slightly for the extra mud weight. Final Circulating Pressure

=

Slow Circulating Rate Pressure

x

Kill Mud Weight . Original Mud Weight

The drill pipe pressure starts dropping below the initial circulating pressure, as the kill mud starts down the drill pipe, reaching the final circulating pressure when the kill mud reaches the bit. Thereafter the drill pipe pressure is held at the final circulating pressure by controlled opening of the choke, as the kill mud moves up the annulus. A graph showing how drill pipe pressure drops from the initial to the final circulating pressure is shown in Figure 3 and this can be used as a guide to the drill pipe pressures required. The drill pipe pressure should drop according to the graph, as kill mud goes to the bit, without the choke being moved.

5-8

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Figure 5.3 1500 1400 1300 ICP 1200 1100 PRESSURE

1000 900

FCP

800 700 600 500 400 300 200 100 0 0

100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700

STROKES Because of the possibility that the annulus may not be circulated completely clean, during the first circulation, it may be preferable to work out how the drill pipe pressure should vary as kill mud is pumped around the well. This will allow the drill pipe pressure to be used throughout, so eliminating the possibility of small gas bubbles in the annulus producing misleading information. The following graphs depict the variations in pressure during the well circulation.

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5-9


Figure 5.4

FIRST CIRCULATION START

Circulating Pressure

FINISH

Pressure Constant

Circulating Pressure at Reduced Rate

Drill Pipe Closed in Pressure

Time or Pump Strokes

START

Annular Pressure

FINISH

ux

nfl

I as

G

Water Influx

Annular Pressure


Profile of Circulating and Annular Pressure While Killing by Driller's Method 5 - 10

V4 Rev March 2002


Figure 5.5

SECOND CIRCULATION Circulating Pressure

START

FINISH

Pressure Constant


Circulating Pressure with Kill Mud

Well Dead in Drill Pipe Drill Pipe Closed in Pressure

Surface to Bit


Annular Pressure

START

FINISH

Constant

Annular Pressure

Surface to Bit


Profile of Circulating and Annular Pressure While Killing by Driller's Method

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5 - 11


Determination of Initial Circulating Pressure If no slow circulating rate pressure has been taken, then the initial circulating pressure can be determined using the start-up procedures described in the circulations of the Driller’s Method. Where the casing pressure has been held constant while the pumps are brought up to a kill rate, the drill pipe pressure reading will be the initial circulating pressure. WARNING: the existence of a predetermined kill rate gives rig personnel a wrong impression that a kick must be circulated exclusively at this rate. The procedure consists of: 1.

Noting casing pressure reading.

2.

Adjusting pumps to new kill rate. Adjusting choke to hold casing pressure constant at the value noted.

3.

As soon as the driller has the pumps settled on the new rate, return to the drill pipe pressure gauge. Note this new reading is the circulating pressure for the new pump rate and maintain this.

4.

Check choke orifice size, in relation to kill rate

NOTE: This procedure is satisfactory at any time during a kill providing the mud weight in the drill string is not changing during the process. It is however preferable to maintain pump rate constant as much as possible. Any decision to change pump rate should be taken early.

5 - 12

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5.4 THE WAIT AND WEIGHT METHOD The “Wait and Weight” is sometimes referred to as the ‘Engineers Method’ or the ‘One Circulation Method’. It does, at least in theory, kill the well in one circulation. Once the well is shut in and pressures stabilised, the shut in drill pipe pressure is used to calculate the kill mud weight. Mud of the required weight is made up in the mud pits. When ready, kill mud is pumped down the drill pipe. At commencement, enough drill pipe pressure must be held to circulate the mud, plus a reserve equivalent to the original shut in drill pipe pressure. This total steadily decreases as the mud goes down to the bit, until with kill mud at the bit, the required pressure is simply that needed to pump kill mud around the well. The choke is adjusted to reduce drill pipe pressure while kill mud is pumped down the string. With kill mud at the bit, the static head of mud in the drill pipe balances formation pressure. For the remainder of the circulation, as the influx is pumped to the surface, followed by drill pipe contents and the kill mud, the drill pipe pressure is held at the final circulating pressure by choke adjustment. Advantages of the Wait and Weight Method •

Lowest wellbore pressures, and lowest surface pressures - this means less equipment stress.

•

Minimum ‘on-choke’ circulating time - less chance of washing out the choke.

Disadvantages of the Wait and Weight Method •

Considerable waiting time (while weighting up) - gas migration.

•

If large increases in mud weight required, this is difficult to do uniformly in one stage.

Procedure for the Wait and Weight Method The Wait and Weight method uses the same calculations already described for a drill pipe pressure schedule. The calculations are: Kill Mud Weight (PPG)

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=

Original Mud Weight + (PPG)

_______(SIDPP)_______ True Vertical Depth x.052

5 - 13


At the start of the circulation, with kill mud: Initial Circulating Pressure (ICP)

=

Slow Circulating Rate Pressure (SCRP)

+

Shut in Drill pipe Pressure (SIDPP)

Once the capacity of the drill string is calculated, it is possible to draw a graph showing how drill pipe pressure varies as kill mud is pumped down to the bit. (See Figure 5.6) Once kill mud is ready, the start-up procedure is as previously described. The choke is cracked open, the pump started to break circulation, and then brought up slowly to the Kill Rate. While the Driller brings the pump up to the Kill Rate, the choke operator works the choke so as to keep the casing pressure at or as near as possible to the closed in casing pressure reading. When the pump is up to the Kill Rate, the choke operator transfers to the drill pipe pressure gauge. As the kill mud proceeds down the drill pipe, the drill pipe pressure is allowed to drop steadily from the Initial Circulating Pressure to the Final Circulating Pressure, by choke adjustment. Where the kick is a small one, at or near the bottom of the hole, the drill pipe pressure tends to drop of its own accord as the kill mud moves down. Little or no choke adjustment is required. Only in cases of diffused gas kicks with gas far up the annulus will significant choke adjustments be needed during this period. After kill mud has reached the bit, the drill pipe pressure is maintained at the Final Circulating Pressure, until the kill mud returns to surface. As with the Driller’s method, this Final Circulating pressure is held constant as long as pump rate is held constant at the selected value. If, for any reason, the pump rate is felt to be wrong, it can be changed using the same procedure described previously. However, pump rate changes should be avoided, where possible. While the pump rate is adjusted, the casing pressure is held steady by adjusting the choke. Once the pump is stabilised at its new speed, the revised circulating pressure is read from the drill pipe gauge. If a gas influx is very near to the surface, adjusting pump rate by holding a steady casing pressure may significantly increase the bottom hole pressure. This is due to the rapid expansion of gas near the surface. Alterations in pump rate are to be made early on! The following two graphs depict pressure variations during the Wait and Weight method. 5 - 14

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Figure 5.6

Circulating Pressure

START

FINISH

Pressure Constant Circulating Pressure with Kill Mud


Well Dead in Drill Pipe Drill Pipe Closed in Pressure

Surface to Bit


Annular Pressure

START

PH1

PH2

FINISH

PH3

PH4

Annular Pressure

Surface to Bit


Profile of Circulating and Annular Pressure Killing by Wait and Weight Method V4 Rev March 2002

5 - 15

5 - 16

I.C.P.

D

F.C.P.

Kill Mud Weight

A

CASING PRESSURE AT MAXIMUM

SICP

DRILLPIPE PRESSURE DROPPING

Casing Pressure at its maximum value

GAS AT SURFACE

WAIT & WEIGHT

Just starting kill mud down drill pipe

Gas Kick

E F.C.P.

CIRCULATING KILL MUD DOWN

START OF KICK

F

Small Casing Pressure still held - as light mud from drillpipe circulated out

DRILL PIPE CONTENTS AT SURFACE

WAIT & WEIGHT

F.C.P.

F.C.P.

Kill Mud Weight

C

Drill pipe pressure dropping from Initial Circulating Pressure to Final Circulating Pressure Casing Pressure rising very slowly (little gas expansion)

WAIT & WEIGHT

SMALL CASING PRESSURE

CASING PRESSURE V. SLOWLY RISING

WAIT & WEIGHT

Kill Mud Weight

B

0

CASING PRESSURE V. SLOWLY RISING

Well ‘clean up’ takes some time, as small residual Casing Pressure is likely

WELL KILLED

WAIT & WEIGHT

Drill pipe Pressure now steady at Final Circulating Pressure

KILL MUD AT BIT

WAIT & WEIGHT


SECTION 5 : METHODS OF WELL CONTROL

Figure 5.7

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5.5 VOLUMETRIC WELL CONTROL The volumetric method is mostly used in workover and production operations. It is a means of allowing the gas to migrate to surface under control. The gas needs to migrate at over (approx.) 1000' per hour. To allow the bubble to expand the casing gauge is held constant for a given volume of mud bled off. This operation is repeated, holding an ever increasing pressure on the gauge until the gas reaches the surface. This is to ensure the BHP is constant. WHEN TO USE VOLUMETRIC WELL CONTROL •

A gas kick is taken and is migrating and the drill string is plugged and only casing pressure can be read.

•

No drill string in the well, packer leaking, wireline logging and swabbed gas migrating. Figure 5.9 Example of volumetric well control with a plugged bit 0 700 WELL DATA

130 bbls

TVD TVD Shoe DP/csg/OH cap DC/OH cap Mud wt Influx Grad Casing Press

= = = = = = =

12000' 8000' 0.0459 bbl/ft 0.0291 bbl/ft 12.0 ppg 0.12 psi/ft 700 psi

Active pit volume before kick = 120 bbls Active pit volume after kick = 130 bbls

For calculating safety margins and working margins use the universal volumetric well control equation below:P.choke

=

Pann + Ps + Pw

Pa

=

Initial SICP

Ps

=

Built in safety margin prior to volumetric well control commencing. Recommended safety margin = 100 - 200 psi

Pw

=

Working margin for volumetric well control Recommended working margin = 50 - 100 psi

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5 - 17


P.choke

= = =

Pann + Ps + Pw 700 + 100 + 50 850 psi

5.5.1 Allow the casing pressure to increase to 850 psi. Note the time taken for this pressure increase then estimate percolating rate in ft/hr. Example:Pressure increased by 150 psi in 15 minutes or 600 psi/hr Percolating rate=

Note:

Pressure increase/hr ––––––––––––––––– Mud grad psi/ft

=

600 psi ––––––––– 0.624 psi/ft

=

962 ft/hr

With this percolating rate it will take approximately 12 hours to get the influx to the surface and it should also be noted percolating rate may increase when gas is close to surface.

5.5.2 When casing pressure is at 850 psi bleed off at choke a volume of mud equal to the working pressure (50 psi). Note:

Casing pressure must be kept constant at 850 psi during this operation. After 50 psi of mud equivalent has been bled off at choke allow the gas to migrate unexpanded until a further 50 psi of overbalance is attained. Bleed off 50 psi equivalent mud at choke and repeat procedure until gas is at choke. The next step lubrication will be discussed later.

5.5.3 CALCULATIONS FOR MUD VOLUME TO BLEED FOR PW A.

5 - 18

Around drill collars mud volume to bleed

=

OH/DC's Cap Pw x ––––––––––– Mud grad

=

0.0291 50 X –––––– 0.624

=

2.3 bbls

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B.

Around Drill Pipe Mud volume to bleed

=

DP/OH Casg Cap Pw x –––––––––––––– Mud Grad

=

0.0459 50 x –––––– 0.624

=

3.6 bbls

5.5.4 GRAPHICAL EXAMPLE OF A VOLUMETRIC BLEED Figure 5.10

1000 Bleed off 3.6 bbls Allow gas to migrate until casing pressure read 850 psi 900

2

3

4 Bleed off 3.6 bbls keeping choke pressure ± 20 psi either side of 900 psi Influx around D.pipe

Bleed off 2.3 bbl keeping choke pressure ± 20 psi either side of 850 psi influx around DC's

800

700

5 Bleed off 3.6 bbls

1

First build up when well was shut in

600

500

Time

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5 - 19


5.5.5 Figure 5.11 shows what is happening to the gas in the well. Figure 5.11 0

0 700

original volume (10 bbls)

0 850

(10 bbls)

0 850

(12.3 bbls)

0 900

(15.9 bbls)

0 950

(18.5 bbls)

1000

(22.1 bbls)

Gas volume in bbls at the end of each mud bleed.

Clearly the description outlined is simplified. Four bleeds are shown. Depending upon the size of the volume bled and the well depth more or less bleeds may be required than illustrated here. Important Points

5 - 20

1.

Bleed mud at constant choke pressure using the manual choke. Ensure crew trained not to be tempted to bleed off faster than this as more influx could be induced into the well. A major problem with the method could be boredom, careful records must be kept of pressure and volumes.

2.

Gas may not conveniently migrate up the well in one bubble. As soon as gas reached choke, stop bleeding until rest of gas catches up. This may build up an unacceptable overbalance and each situation will have to be judged on the operational merits of the situation.

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5.5.6 LUBRICATION Once gas is at choke stop the bleed operation and commence pumping mud into the well using the kill line. The procedure for lubrication is as follows:1.

Pump slowly into kill line and let kill and choke line pressure equalise before opening kill line stack valves.

2.

Pump 3.6 bbls mud into annulus and allow the mud time to fall through the gas, then bleed off pressure at the choke equal to the hydrostatic pressure of the mud pumped into the annulus.

Example:Pressure to bleed

3.

=

Pumped volume ––––––––––––– x Mud grad Ann Cap

=

3.6 –––––– x 0.624 0.0459

=

50 psi

Repeat the lubrication process until all the gas has been replaced with mud and referring to the drawing in figure 5.11, this will take approximately 22.1 bbls. Note:

V4 Rev March 2002

Pit volume should return to 120 bbls the volume in active pit before kick was taken.

5 - 21


Figure 5.12 Graphical example of lubricating mud into annulus 1050

p m Pu

6 3.

ls bb

After pumping mud into annulus, waiting period allows mud to fall then bleed gas until casing pressure reduces by 50 psi below original pressure.

1000 950 900 850

Casing Pressure

800 750 700 650 600 550 500 450 Pit Volume

400 350

152.1 148.5 3.6

145

141

138

134

130.5

127

123

120

7.2

10.8

14.4

18

21.6

25.2

28.8

32.4

Barrels Pumped

1.

Original Pit Volume = 120 bbls Pit volume after kick and volumetric bleed = 152.1 bbls

2.

Formation pressure = = = =

SICP + P° hyd mud + P° hyd gas 700 + (11656 x 0.624) + (344 x 0.12) 700 + 7273 + 42 8015 psi

BHP after lubrication = = = =

SICP + P° Hyd mud 550 + (12000 x 0.624) 550 + 7488 8038 psi

5.5.7 Once the volumetric bleed and lubrication has been completed then the well must be circulated to kill mud. This can be done by running wire line and perforating drill pipe or drill collars. If all the gas has been bled from the annulus then SICP can be used to calculate the kill mud.

5 - 22

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5.6 VOLUMTRIC STRIPPING 5.6.1 Example of Volumetric Stripping The options available if an influx is swabbed or if the well starts flowing during a trip are as follows:a)

If well is not flowing, trip back to bottom keeping a careful check on returns. Then circulate influx out of hole.

b)

If well is flowing and is shut in and the gas is percolating with the bit a long way off bottom and tight hole conditions have been experienced, then consider doing a volumetric bleed.

c)

If well is flowing and is shut in and the gas is percolating with the bit a long way off bottom and tight hole conditions have been experienced, then consider bullheading.

d)

If well is flowing and is shut in and the gas is percolating and no problems are anticipated in stripping back to bottom, then consider volumetric stripping to get bit to bottom. Circulate influx out using first circulation of Driller's Method.

Note:

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A swabbed kick well can be most effectively killed with bit on bottom. So every effort must be made to get bit safely back on bottom.

5 - 23


5.6.2 Well details Figure 5.13 108 108

Bit size TVD TVD shoe Bit Depth DP Cap DP Disp DP/OH cap Mud wt Pit Gain Influx Grad

= = = = = = = = = =

8 1/2" 12,000' 9,000' 11,000' 0.02776 bbl/ft 0.0075 bbl/ft 0.0459 bbl/ft 12.0 ppg 15.0 bbls 0.12 psi/ft

Bit depth at original shut in = 11,000'

15 bbls

Figure 5.14 0 560

Shut in pressures and influx size with bit on bottom.

24.5 bbls

5 - 24

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5.6.3 Shut in procedure for a swabbed kick while tripping Fast shut-in 1.

Stab safety valve (kelly cock).

2.

Close safety valve.

3.

Open HCR fail safe valves.

4.

Close annular.

5.

Read casing pressure and if possible read drill pipe pressure.

6.

Stab inside BOP (Gray valve).

7.

Open safety valve.

8.

Do stripping calculations, prepare stripping sheet.

9.

Reduce annular pressure and commence stripping drill pipe.

Note:

The above procedure (steps 1 through 5) assumes there is no float or non-return valve in the drill string.

5.6.4 For calculating safety margins and working margins use the universal volumetric well control equation below:P.choke

=

Pann + Ps + Pw

Pa

=

Initial SICP

Ps

=

100 psi + *Increase in casing pressure with influx around drill collars * ∆P.csg = Mud grad - Influx grad x (H2 - H1)

Pw

=

Working margin (Recommended working margin = 50 - 100 psi)

H1

=

15 –––– 0.07

Pa

=

108 psi

Ps

= = =

100 + (0.624 - 0.12) x (514 - 214) 100 + 0.504 x 300 251 psi

Pw

=

50 psi

P.choke

= =

108 + 251 + 50 410 psi

V4 Rev March 2002

=

214'

H2

=

15 ––––– 0.0292

=

514'

5 - 25


Theoretical bleed off in bbl/ft while stripping

= = =

DP displacement + DP cap 0.01776 + 0.0075 0.02526 bbl/ft

( (

Excess bleed off for each 50 psi working margin = Pw x = 50 x = Note:

Ann Cap –––––––––– Mud grad

0.0292 ––––––– 0.0624

)

)

2.3 bbls

If the gas is not migrating while stripping, only theoretical bleed off will be seen in strip tank. If gas is migrating then any excess bleed off is due to migration. When excess bleed off is ± 2.3 bbls, then build in another 50 psi working pressure. Refer to Volumetric Stripping chart (Fig. 5.15). Figure 5.15 P° choke

1

1.00

1.20

0.20

410

2

3.37

4.53

1.16

410

3

5.74

7.86

2.12

460

4

7.74

10.72

2.98

460

5

10.11

14.05

3.94

460

6

12.48

17.38

4.90

510

7

14.48

20.18

5.70

510

8

16.85

23.51

6.66

510

9

19.22

26.84

7.62

560

10

21.59

30.07

8.48

560

11

23.96

33.41

9.45

Step 1 108 –>410

Step 2

Step 3

Step 4

5 - 26

ACCUMULATIVE VOLUMES Average length = 94' Theoretical Actual vol. Excess vol. No. Stands vol. bleed off bleed off bleed off After 50' pressure at 410 psi

After 15' stripped pressure at 460 psi



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Step 1

Allow casing pressure to increase to calculated Pchoke pressure while stripping first stand, then hold casing pressure constant by bleed off at choke.

Note:

The casing pressure may not rise straight away because the gas has to be compressed. It may take 2 - 3 stands before a pressure build up is seen.

Step 2, 3 & 4

With theoretical bleed already calculated, record actual bleed, when the difference between the actual and theoretical bleed is 2.3 bbls allow annulas pressure to increase by Pw (50 psi). Figure 5.16

600 Step 4 500

Step 3

Pressure

Step 2 400

Step 1

300 200 100 0

1

2

3

4

5

6 7 Stands

8

9

10

11

12

5.6.5 With bit on bottom casing pressure reads 560 psi, gas influx has expanded by 9.45 bbls and if it was possible to read drill pipe pressure it would read zero with drill pipe full of mud. The influx should now be circulated out using auto choke. Note:

No kill mud will be required as this is a swabbed kick.

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5 - 27


5.7 EDITED EXTRACT FROM API RP53 PIPE STRIPPING ARRANGEMENTS - SURFACE INSTALLATIONS PURPOSE During operations on a drilling or producing well, a sequence of events may require tubing, casing, or drill pipe to be run or pulled while annular pressure is contained by blowout preventers; such practice is called “stripping”. Stripping is normally considered an emergency procedure to maintain well control; however, plans for certain drilling, completion, or well work operations may include stripping to eliminate the necessity of loading the well with fluid. EQUIPMENT Stripping techniques vary, and the equipment required depends upon the technique employed. Each stripping operation tends to be unique, requiring adaptation to the particular circumstances. Therefore, the equipment and the basic guidelines discussed herein are necessarily general in nature. Stripping requires surface equipment which simultaneously: a.

permits pipe to be pulled from or run into a well,

b.

provides a means of containing and monitoring annular pressure, and

c.

permits measured volumes of fluid to be bled from or pumped into the well.

Subsurface equipment is required to prevent pressure entry or flow into the pipe being stripped. This equipment should either be removable or designed so that its presence will not interfere with operations subsequent to stripping. The well site supervisor and crew must have a thorough working knowledge of all well control principles and equipment employed for stripping. Equipment should be rigorously inspected, and, if practicable, operated prior to use. For stripping operations, the primary surface equipment consists of blowout preventers, closing units, chokes, pumps, gauges, and trip tanks (or other accurate drilling fluid measuring equipment). The number, type, and pressure rating of the blowout preventers required for stripping are based on anticipated or known surface pressure, the environment, and degree of protection desired. Often the blowout preventer stack installed for normal drilling is suitable for low pressure stripping if spaced so that tool joints or couplings can be progressively lowered or pulled through the stack, with at least one sealing element closed to contain well pressure.

5 - 28

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Annular preventers are most commonly employed for stripping because tool joints and some couplings can be moved through the preventer without opening or closing of the packing element. Wear of the packing element limits the sole use of this preventer if high annular pressure must be contained while stripping. To minimise wear the closing pressure should be reduced as much as possible and the element allowed to expand and contract (breathe) as tool joint pass through. Lubrication of the pipe with a mixture of oil and graphite or by permitting a small leakage of annular fluid will reduce wear on the packing element. A spare packing element should be at the well site during any stripping operation. Ram type preventers or combinations of ram and annular preventers are employed when pressure and/or Configuration of the coupling could cause excessive wear if the annular preventer were used alone. Ram preventers must be opened to permit passage of tool joints or couplings. When stripping between preventers, provision should be made for pumping into and releasing fluid from the space between preventers. Pressure across the sealing element should be equalised prior to opening the preventer to reduce wear and to facilitate operation of the preventer. After equalising the pressure and opening the lower preventer a volume of drilling fluid equal to that displaced as the pipe is run into or pulled from the well should be, respectively, bled from or pumped into the space between the preventers. Chokes are required to control the release of fluid while maintaining the desired annular pressure. Adjustable chokes which permit fast, precise control should be employed. Parallel chokes which permit isolation and repair of one choke while the other is active are desirable on lengthy stripping operations. Because of the severe service, spare parts or spare chokes should be on location. Fig. 10.A.1 illustrates an example choke installation on the standpipe suitable for stripping operations. A pump truck or skid mounted pump is normally employed when stripping out. The relatively small volume of drilling fluid required to replace the capacity and displacement of each stand or joint of pipe may be accurately measured and pumped at a controlled rate with such equipment. Well fluid from below the preventer should not be used to equalise pressure across the stripping preventer. A trip tank or other method of accurately measuring the drilling fluid bled off, leaked from, or pumped into the well within an accuracy of one-half barrel is required. 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 components of the blowout preventer stack fail. It should not be subjected to the wear and stress of the stripping process.

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5 - 29


5.8 REMOVAL OF GAS TRAPPED IN BOP’S In order to displace a gas kick completely from the wellbore several circulations of the well might be needed. During this time some of the gas may have become trapped under closed rams in the BOP stack as shown in Fig 5.28. This has the potential to cause a serious problem if the gas is not removed in a controlled manner. If the rams were opened without removing the trapped gas, the gas would be released into the riser. As the gas migrated, it would expand rapidly and cause the riser to unload mud onto the rig floor. The most thorough method of gas removal is to leave the well shut on the lower rams whilst displacing the choke and kill lines to water. By closing the kill line valves, pressure can be bled off up the choke line and “U-tubed” up the choke line by opening the pipe rams. This sequence is shown in Fig 5.29 and 5.30. The surface diverter should be closed during the operations so that any residual gas from the riser can be safely dealt with. Once the riser has been displaced to kill weight mud the lower rams can be opened and the well flow-checked. Calculate any new riser margin or trip margin that might have to be added to the mud weight. Figure 5.28 TRAPPED GAS IN BOP STACK KILL LINE

CHOKE LINE

UPPER ANNULA R

BLIND/SHEAR RAMS

LOWER ANNULA R

PIPE RAMS

PIPE RAMS

PIPE RAMS

5 - 30

V4 Rev March 2002


Figure 5.29 REMOVING TRAPPED GAS FROM BOP STACK KILL LINE

CHOKE LINE

Isolate the well from the BOP stack by closing the lower pipe rams.

KILL LINE

CHOKE LINE

KILL LINE

CHOKE LINE

Slowly displace kill line to salt water. As the kill line is displaced to water, increase the kill line circulating pressure by an amount equal to the difference in hydrostatic pressure between kill mud and salt water at stack depth. This will maintain the gas at original pressure with clean salt water returns at surface stop pumping close choke.

Displace riser to kill mud using upper kill line.

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5 - 31


Figure 5.30 REMOVING TRAPPED GAS FROM BOP STACK KILL LINE

CHOKE LINE

CHOKE LINE

Close the subsea kill line valves.

Close the diverter and line up to fill the riser.

At this point the pressure is still trapped in the gas bubble.

Open the pipe rams and allow the riser to U-tube taking returns up the choke line.

Bleed off pressure through the choke to allow the gas to displace water from the choke line.

Fill the riser as necessary.

The gas bubble should now be at close to atmospheric pressure.

5 - 32

KILL LINE

Open the lower pipe rams and diverter element. Flow check the well.

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Bubble Expansion Example:Choke Line Length Choke Line Volume Kill Mud Sea Water Grad

= = = =

1000' 8 bbls 15 ppg 0.445

=

780 X 3 ––––––– 445

V2

=

P1 V1 –––– P2

P1

=

15 x 1000 x 0.052

V1

=

3 bbls

P2

=

0.445 x 1000

=

5.3 bbls =

=

780 psi

445 psi

Example: This example gives some idea of the large volumes of gas that could be released to atmosphere if the annular is opened without sweeping the stack. Lets say that we are drilling in 1800' of water and the well has been killed to surface, via the choke line with 16.5 ppg mud. The hydrostatic head compressing the gas under the bag would be (1800 x 16.5 x .052) + 14.7 = 1559 psi If the volume of gas trapped below the BOP = 5.46 bbls then: P1 x V1 –––––– P2

= V2

1559 x 5.46 –––––––––– = 579 bbls 14.7

573 bbls of gas released at surface.

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5 - 33


5.9 KICK DETECTION AND WELL CONTROL PROBLEMS ON DEVIATED AND HORIZONTAL WELLS Figure 5.31 A - SURFACE 30" Shoe TVD = 1000'

MD = 1000'

20" Shoe TVD = 2500'

MD = 2500'

B - KICK OFF POINT (K.O.P.)

13 3/8" Shoe TVD = 5000'

MD = 5500'

Mud Weight = 10.0 ppg 9 5/8" Shoe TVD = 9500' Formation Pressure = 4700 psi

MD = 17500'

C - END OF BUILD (E.O.B.) MD at C = 12500' Well Depth TVD = 10000'

D - TOTAL MEASURED DEPTH (M.D.)

MD = 15000'

INTRODUCTION Kick behaviour can be significantly different in highly deviated and horizontal wells. If influx is mainly gas, problems can be experienced getting the gas to move out of the horizontal section. It maybe impossible to remove the gas if the horizontal section is greater than 90 degrees. Swabbed influxes can be hard to detect in horizontal sections and care must be taken while making connections or tripping in these sections of the hole. Drill pipe pressure graphs will also be significantly different for horizontal and deviated wells. 5.9.1 KICK DETECTION AND PRECAUTIONS TO TAKE WHILE DRILLING

5 - 34

a)

First indication of a kick while drilling would be an increase in flow rate.

b)

If the increase in flow rate is not picked up then the second indication of a kick would be a pit level increase.

c)

While drilling the horizontal section mixing chemicals or slow addition of mud into the active system should be avoided

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5.9.2 KICK DETECTION AND PRECAUTIONS TO TAKE WHEN MAKING CONNECTIONS. a)

The equivalent circulating density is relatively higher when drilling high angle wells. While drilling, the trip tank should be kept half full of mud when pumps are off. During a connection well should be lined up on trip tank as the most likely time to swab or take a kick is when APL is lost with pumps off.

b)

If an influx has been swabbed in and not picked up during a connection no increase pit level will be seen until influx is out of horizontal section. If it is a gas influx in an oil base mud then no increase maybe seen until influx reaches bubble point usually ± 3000 feet beneath mud return flow line. The driller and mud logger should pay particular attention to flow rates and pit levels when connection gas moves out of horizontal section or is ± 3000 feet beneath mud return flow line.

5.9.3 KICK DETECTION AND PRECAUTIONS TO TAKE WHILE TRIPPING.

a)

Mud loggers will calculate maximum tripping speed to avoid swabbing.

b)

Check mud rheology is within specifications prior to tripping, high mud rheology can lead to swabbing.

c)

When tripping out of horizontal section there are two options available and a slug should not be pumped until bit is inside 9 5/8" casing. 1.

Line up to trip tank pull out to 9 5/8" shoe monitoring hole fill in trip tank ADVANTAGES: Accurate record of hole fill. DISADVANTAGES: Pulling out of hole with pumps off there is no APL to Act as a safety margin.

2.

Pull out of hole to 9 5/8" shoe back reaming and circulating. ADVANTAGES: While circulating annular pressure loss will be acting on formation and should prevent swabbing. DISADVANTAGES: If an influx is swabbed in, it would be very hard if not impossible to detect.

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5 - 35


5.9.4 GAS KICK IN HORIZONTAL SECTION.

5 - 36

a)

Gas will not migrate if hole angle is 90 degrees or greater.

b)

Gas will not migrate if it is dissolved in oil based mud.

c)

Gas maybe trapped in undulations or washouts or in hole sections which are greater than 90 degrees.

d)

If gas cannot be removed from inverted sections then consider bullheading gas into formation.

e)

Slow circulating rates which give a flow rate greater than 130 ft/min while circulating gas out of horizontal section should be considered. Flow rates lower than this may not remove the gas from the horizontal section

f)

A swabbed influx will not give a SICP if shut in while it is in horizontal section.

g)

Referring to drawings on page 1 it would be impossible to take a kick if formation pressure remains at 4700 psi. If a fault is drilled and formation pressure increases and the well is shut on a kick then SIDPP = SICP and the gradient of the influx cannot be calculated.

V4 Rev March 2002


Drill pipe kill graph for a vertical well using well details from Fig 5.31 Additional Information SIDPP PSCR (Up Riser) Pump Output Drill Pipe Cap BHA Cap Drill String Cap

= = = = = =

Strokes to Disp D.string

=

600 psi 700 psi 0.117 bbl/stks 0.01776 bbl/ft 1000' X 0.008 bbl/ft 9000 X 0.01776 = 159.8 1000 X 0.008 = 8.0 167.8 bbl 167.8 ––––– 0.117

Press Step Down psi/stks =

1. Kill Mud wt

2. ICP

3. FCP

V4 Rev March 2002

= 1434 stks

ICP - FCP 1300-784 –––––––––––––– = ––––––––– = 0.36 psi/stks Surface to bit stks 1434

=

600 ––––– 10000

=

11.2 ppg

=

600 + 700

=

1300 psi

=

11.2 700 x –––– 10

=

784 psi

÷ 0.052 + 10.0

5 - 37


Figure 5.32 1500 1400 1300 ICP 1200 1100

PRESSURE

1000 900

FCP

800 700 600 500 400 300 200 100 0 0

100

200

300

400

500

600

700

800

900 1000 1100 1200 1300 1400 1500 1600 1700

STROKES To construct this graph calculate ICP and FCP and strokes to displace the drill string then draw a line between the two points. IT SHOULD BE NOTED THAT THIS GRAPH IS MADE UP OF TWO DIFFERENT PRESSURES No 1 Is the SIDPP which will decrease from 600 psi to zero when kill mud is at the bit. No 2 Is the SCR pressure which increases from 700 psi to 784 psi when the kill mud is at the bit.

5 - 38

V4 Rev March 2002


Drill pipe kill graph for a horizontal well using well details from Fig 5.31 Additional Information SIDPP PSCR (Up Riser) Pump Output Drill Pipe Cap BHA Cap Drill String Cap

= = = = = =

Strokes to Disp D.string

=

600 psi 1050 psi 0.117 bbl/stks 0.01776 bbl/ft 1000' X 0.008 bbl/ft 14000 X 0.01776 = 248.6 1000 X 0.008 = 8.0 256.6 bbl 256.6 ––––– 0.117

= 2194 stks Figure 5.33

A - (SURFACE)

B - (K.O.P.)

MD = 2500' TVD = 2500'

MD = 12500' TVD = 10000'

MD = 15000' TVD = 10000'

C - (E.O.B.)

1. Kill Mud wt

=

600 ––––– ÷ 0.052 + 10.0 10000

=

2. ICP

=

600 + 1050

1650 psi

=

11.2 1050 x –––– 10

3. FCP

V4 Rev March 2002

=

=

D - (M.D.)

11.2 ppg

1176 psi

5 - 39


Figure 5.34

1700 A - (SURFACE) 1650 1600 B - (K.O.P.) 1521 1500

PRESSURE

1400 1300 D - (M.D.) 1170

1200 1100

C - (E.O.B.) 1155

1000 800 600 400 200 0 0

200

400

600

800 1000 1200 1400 1600 1800 2000 2200 2400 2600

STROKES

The calculations for Figure 34 are as follows:1. Pressure Drop from A to B Static drill pipe pressure drop to point (B) = SIDPP -

=

2500 600 - ––––– x 600 10000

= 600 - 150

(

TVD(B) ––––––– x SIDPP TVD

= 450 psi

Frictional pressure increase at point (B) = SCR UP RISER +

=

1050 +

(

)

2500 –––––– x 126 15000

)

(

)

MD(B) ––––– FCP-PSCR MD

= 1050 + 21 = 1071 psi

Pressure drop from A–> B = 1650 –> (1071 + 450)

= 1650 psi –> 1521 psi

44.4 Strokes from A–> B 2500 x 0.01776 = –––––– = 380 strokes 0.117

5 - 40

V4 Rev March 2002


2. Pressure drop from B to C Static drill pipe pressure drop to point (C) = SIDPP = 600 -

(

10000 ––––– x 600 10000

)

(

)

12500 –––––– x 126 15000

)

= 0 psi

Frictional pressure increase at point C = SCR +

= 1050 +

(

TVD(C) –––––– x SIDPP TVD

(

MD(C) ––––– x ∆P SCR MD

= 1050+105

)

= 1155 psi

Pressure drop from B to C = 1521 to 1155 psi Strokes from B to C = (12500 - 2500) x 0.01776 = Accumulative strokes = 380 + 1518

( )

177.6 ––––– = 1518 strokes 0.117

= 1898 strokes

3. Frictional pressure increase from point C to point D Frictional pressure at C = 1155 psi Frictional pressure at D = 1176 psi Strokes from C to D = (12500 - 14000) x 0.01776 =

1000 x 0.008

=

8 –––– 0.117

26.64 –––––– 0.117

= 228 strokes

= 68 strokes 296 strokes

Accumulative strokes to point D = 380 + 1518 + 296

V4 Rev March 2002

= 2194 strokes

5 - 41


5.10 KICK TOLERANCE When a gas influx has entered a well there are 2 critical locations for the influx:a)

When the influx is at the bottom of the well. In this case the SICP must not exceed the MAASP, if the formation is not fractured at the casing shoe.

b)

When the influx has been circulated up to the casing shoe, by a constant bottom hole pressure method. In this case, the pressure at the choke must not exceed the MAASP. KICK TOLERANCE DEPENDS UPON:-

Formation strength, fracture pressure or fracture gradient. Mud density or gradient. Gas influx density or gradient. Formation pore pressure, gradient or SIDPP. Drill string and wellbore geometries. The maximum tolerable length of gas influx in the annulus at any position between bottom hole and the casing shoe is:-

Where:-

5 - 42

H (Max)

=

MAASP - SIDPP G m - Gi

(Eqn1)

GM

=

mud gradient (psi/ft)

GI

=

influx gradient (psi/ft)

MAASP

=

(Gfrac - Gm) x Ds (psi)

Gfrac

=

formation fracture gradient at the shoe (psi/ft)

DS

=

TVD to the shoe (ft)

SIDPP

=

shut-in drillpipe pressure (psi)

V4 Rev March 2002


KICK TOLERANCE : DRILLED KICK MAASP SICP E

PRESSURE

L BDE

=

pressure profile in annulus at shut-in.

BD

=

initial gas influx height = H1

BMFKL =

pressure profile in annulus when top of gas is circulated to casing shoe, by 'drillers method'.

SK

=

fracture pressure at shoe.

FK

=

maximum tolerable length of expanded gas influx at shoe = HMAX.

Mud

DEPTH (TVD)

0

dien

Gra

∆le FKN = ∆le BDM.

ine

re L

effu

t/Pr

Hence HMAX = MAASP - SIDPP GM - GI

Shoe

S

N

K

eL

r ctu

Fra

H max (gas)

F

ine M A Phyd

D B

H1(gas)

Ppore C SIDPP

NB. Well geometry assumed to be constant

V4 Rev March 2002

5 - 43


DEFINITION 1: for a kick taken while drilling into a high pressure formation. Kick Tolerance is the maximum allowable influx volume, for a known or assumed SIDPP, which will not cause the formation to fracture when either the influx is at the bottom of the annulus or when it is circulated and expanded to the casing shoe by a constant bottom-hole pressure method. (Usually the Driller's method). Thus the kick tolerance is either a)

H V1g = Ldc x Vdca bbl (If H is
or

- Ldc) bbl (if H is >Ldc) V1g = Vdca + (HCdpa

where H is calculated from Eqn 1 OR b)

x (MAASP - SIDPP) bbl V1g = Pfrac Ppore x (GM - GI) x Csa

The Lower value of V1g calculated from a) and b) is the Kick Tolerance. Where:-

5 - 44

Vdca

=

Volume of DC/OH annulus, (bbl)

Ldc

=

(Vertical) length of drill collars, (ft)

Cdca

=

Capacity of DC/OH annulus (ft/bbl)

Cdpa

=

Capacity of DP/OH annulus (ft/bbl)

Csa

=

Capacity of annulus (ft/bbl) at the casing shoe - this will probably = Cdpa, but on occasion it may = Cdca

Pfrac

=

fracture pressure at shoe (psi)

Ppore

=

pore pressure at bottom of hole (psi)

V4 Rev March 2002


DEFINITION 2: for a kick taken while tripping out of the hole. Kick tolerance for a swabbed kick is the maximum allowable influx volume which may be swabbed into the bottom of a well, without fracturing the formation when the well is closed in, and when the mud gradient is at the least equal to the formation pore pressure gradient. It is assumed that prior to tripping, the mud weight was correct. In this case, when the bit is eventually back at bottom SIDPP=0, although initially SIDPP should = SICP (no float) when the well is closed in and the bit is above the influx. In this case

Hmax

= MAASP GM - GI ft

and the kick tolerance is either

or

V1g =

H Ldc x Vdca

V1g =

- Ldc) Vdca + (H Cdpa

V4 Rev March 2002

5 - 45


KICK TOLERANCE EXERCISE 1 A well has a TVD of 14500 ft with the casing shoe at 13200 ft TVD. The fracture gradient is 0.87 psi/ft and the current mud is 15.3 ppg. There is 700 ft of 6 1/2" OD drill collar and the open hole diameter is 8 1/2", with 5" drill pipe. The annular capacities are:DC/OH

= 34.314 ft/bbl

DP/OH

= 21.787 ft/bbl

1)

Calculate the kick tolerance if the well is shut-in with the current mud and a SIDPP of 570 psi. The gas gradient is 0.1 psi/ft.

2)

Calculate the kick tolerance for a swabbed kick when the mud weight is equivalent to the formation pore pressure. The mud gradient is 0.835 psi/ft.

5 - 46

V4 Rev March 2002


SOLUTION 1)

MAASP

= (Gfrac - GM) x DShoe G = 15.3 x 0.052 = 0.7956 psi/ft M = (0.87 - 0.7956) x 13200 = 982 psi

Then H1 max

= MAASP - SIDPP GM - GI =

982 - 570 . 0.7956 - 0.1

= 592.3 ft a)

For influx at the bottom of the well, influx is still within the DC/OH annulus, at its maximum. Volume of DC/OH annulus=

Therefore: b)

700 34.314

= 20.40 bbl

Kick tolerance (a) = 592.3 x 20.40 700

= 17.3 bbl

For kick at casing shoe, Kick tolerance (b)

Gpore

=

Pfrac x (MAASP - SIDPP) Ppore x Cdpa x (GM - GI)

=

Gfrac x (MAASP - SIDPP) x Dshoe Gpore x Cdpa x (GM - GI) x TVD

=

15.3 x 0.052 x 14500 + 570 = 0.835 psi/ft 14500

Therefore: kick tolerance (b) = conclusion:

V4 Rev March 2002

0.87 x (982 - 570) x 13200 = 25.8 bbl 0.835 x 21.787 x (0.7956 - 0.1) x 14500

The smaller of those 2 values is the (a) value therefore kick tolerance = 17.3 bbl when the kick is in the DC/OH annulus. This is usually the case in short open-hole sections.

5 - 47


2)

For a swabbed kick, maximum allowable (SIDPP = 0) influx height is: Hmax

= MAASP ft GM - G I

New MAASP

= (0.87 - 0.835) x 13200

= 462 psi Therefore H1 max =

462 0.735

= 628.6 ft

Therefore swabbed kick tolerance with 0.835 psi/ft mud. = 628.6 x 20.4 700 = 18.3 bbl

5 - 48

V4 Rev March 2002


WORKSHOP 5

The following questions 1-5 refer to the first stage of the Drillers Method. 1.

A well was shut-in on a kick that occurred whilst drilling. During the first circulation of the Drillers Method, the choke operator maintains a constant drill pipe pressure at a constant pump speed. Will bottom hole pressure: a. b. c.

2.

Referring to the question above, the choke operator has not taken into account the large volume of the surface lines, i.e. from the pump to the rig floor. This will result in: a. b. c.

3.

When pressures have stabilised at shut-in When the kick is going into the shoe When the kick is nearing the surface

What happens to pressure at the shoe as the brine kick is being moved into the casing shoe?: a. b. c.

5.

An increase in bottom hole pressure A reduction in bottom hole pressure No change to bottom hole pressure

Referring to question 1 above if the kick was brine, (with no gas) Casing or Choke pressure will be at its highest : a. b. c.

4.

Be increasing Be decreasing Being kept constant

Pressure at the shoe will be constant Pressure at the shoe will reduce Pressure at the shoe will increase

If the kick is gas rather than brine and as it is being circulated into the casing shoe will: a. b. c.

V4 Rev March 2002

Pressure at the shoe increase Pressure at the shoe decrease Pressure at the shoe remain constant

5 - 49


6.

During the second stage of the Drillers Method, assuming all of the kick was removed during the first stage, if when starting the operation the choke operator maintained a constant initial circulating pressure in the drill-pipe until kill mud reached the bit. Would bottom hole pressure? a. b. c.

7.

If at the start of the second stage of the Drillers Method, the choke operator maintained a constant Casing or Choke pressure until kill mud was at surface. How would this action affect B.H.P. ? a. b.

c.

8.

Be increased Have reduced Be constant

B.H.P. would be seeing an increase from the moment the pump reached kill speed until kill mud was at surface. B.H.P. would have increased until kill mud was at the bit, then B.H.P. would have remained constant as kill mud displaced the annulus. B.H.P. would have remained constant until kill mud at bit then B.H.P. would be increased as kill mud displaced the annulus.

If total losses occur when drilling and with the bit off bottom and the mud pumps off. Sea-water is then pumped to the annulus. Assume the volume of water it took to fill the well to the top was equivalent to 500' of annulus. What is the resultant reduction in bottom hole pressure due to this action ? Mud weight = 10 ppg Sea-water = 8.7 ppg a. b. c.

9.

The well flows with the bit 10 stands off bottom. Shut-in casing pressure reads 200 psi. If the influx is below the bit: a. b. c.

5 - 50

260 psi 226 psi 34 psi

Shut-in drill pipe pressure will be higher than 200 psi Shut-in drill pipe pressure will be lower than 200 psi Shut-in drill pipe pressure should be 200 psi

V4 Rev March 2002


10.

A well is shut-in on a kick whilst drilling and stabilised shut-in pressures have been established. Due to a delay in starting the kill operation surface pressures have increased by 100 psi as the influx is migrating. The safest action would be: a. b. c.

11.

To bleed mud off using the choke until casing pressure reduces by 100 psi. Then keep it constant. Bleed mud off keeping a constant drill pipe pressure. Leave it until the problem causing the delay has been resolved then increase the kill mud weight by .5 ppg.

Referring to Q10. If surface pressure had increased by 200 psi due to migration of the influx. How far has the influx migrated if the mud weight is 10 ppg and the influx density is assumed to be .12 psi/ft ? Answer:

12.

When comparing the Drillers and Wait & Weight Kill Methods with regards to the pressures that will be exerted on the exposed foundations immediately below the casing shoe: Select 2 answers from the following statements. a. b. c. d. e.

13.

The Drillers Method will always give a higher shoe pressure. The Wait & Weight Method will always give a lower shoe pressure. The Drillers Method will give the lowest shoe pressure when the open hole volume is smaller than the string volume. The Wait & Weight Method will give the lowest shoe pressure when the open hole volume is greater than the string volume. There will be no great difference in shoe pressures whether the Drillers or Wait/Weight Method is used if the open hole volume is less than the string volume.

If a well is shut-in on a gas kick and the gas is not allowed to expand as it migrates up the well-bore. What happens ? a.

To B.H.P. (i) It increases (ii) It decreases (iii) Stays more or less the same

V4 Rev March 2002

5 - 51


b.

To surface pressures (i) They increase (ii) They stay more or less the same (iii) Only casing pressure will increase

c.

To pressures at the shoe (i) Will only increase if the influx is below the shoe (ii) Will continue to increase (iii) Will remain fairly constant

d.

Pressures in the gas influx. Assuming no temperature change. (i) Pressure in the gas will continue to increase (ii) Pressure in the gas will keep reducing as it migrates (iii) There should be no great change to the pressures in the gas influx

14.

A kick is being circulated out using the Wait & Weight Kill Method. Shortly after pumping kill mud to the bit, final circulating pressure has suddenly increased by 200 psi. The pump speed has been kept constant at kill speed and there was no change noted on the choke gauge. What is the problem ? a. b. c.

15.

If the choke operator opened the choke and reduced drill pipe pressure back to the calculated final circulating pressure in the problem as described in Question 14. The result would be: a. b. c.

5 - 52

The choke has plugged A bit nozzle has plugged A pack-off has occurred around the bit

B.H.P. would be reduced B.H.P. would be increased no change to B.H.P

V4 Rev March 2002


WORKSHOP 5 - Answers

1.

c.

Being kept constant Maintain ICP with present mud weight until bottoms-up (1st circ. driller's method).

2.

c.

No change to bottom hole pressure Kill mud is not being circulated until the 2nd circulation.

3.

a.

When pressures have stabilised at shut-in When the height of the kick is at its highest: ie around the drill collars.

4.

b.

Pressure at the shoe will reduce Kick fluid is being replaced with a heavier "mud", reducing pressure at the shoe.

5.

b.

Pressure at the shoe decrease Kick fluid is being replaced with a heavier "mud", reducing pressure at the shoe.

6.

a.

Be increased Casing pressure should be constant while DP pressure should reduce from an ICP to a FCP.

7.

c.

B.H.P. would have remained constant until kill mud at bit then B.H.P. would be increased as kill mud displaced the annulus. Casing pressure should reduce as kill mud displaces annulus.

8.

c.

34 psi 500 x (10 - 8.7) x .052 = 33.8 psi

V4 Rev March 2002

5 - 53


9.

c.

Shut-in drill pipe pressure should be 200 psi

10.

b.

Bleed mud off keeping a constant drill pipe pressure.

11.

Answer: 385' 200 psi .52 psift

12.

e.

The Wait & Weight Method will give the lowest shoe pressure when the open hole volume is greater than the string volume. There will be no great difference in shoe pressures whether the Drillers or Wait/Weight Method is used if the open hole volume is less than the string volume.

a.

(i)

It increases

b.

(i)

They increase

c.

(ii)

Will continue to increase

d.

(iii) There should be no great change to the pressures in the gas influx

14.

b.

A bit nozzle has plugged

15.

a.

B.H.P. would be reduced

13.

5 - 54

d.

= 385'

V4 Rev March 2002

SECTION 6 :

WELL CONTROL EQUIPMENT Page

6. 0

API Guidelines - API RP53

1

6. 1

Ram Blowout Preventers

10

6. 2

Annular Preventers

38

6. 3

Diverters

57

6. 4

Gaskets, Seals and Wellheads

72

6. 5

Manifolds

84

6. 6

Inside BOP’s

102

V4 Rev March 2002

WELL CONTROL for the Rig-Site Drilling Team SECTION 6 : WELL CONTROL EQUIPMENT

6.0 API GUIDELINES (API RP53) BLOWOUT PREVENTER STACK ARRANGEMENTS SURFACE INSTALLATIONS CLASSIFICATION OF BLOWOUT PREVENTERS API classification of example arrangements for blowout preventer equipment is based on working pressure ratings. Example stack arrangements shown in Figs. C.1 to C.9 should prove adequate in normal environments, for API Classes 2M, 3M, 5M, 10M and 15M. Arrangements other than those illustrated may be equally adequate in meeting well requirements and promoting safety and efficiency. STACK COMPONENT CODES The recommended component codes for designation of blowout preventer stack arrangements are as follows: A G R

= = =

Rd

=

Rt

=

S M

= =

annular type blowout preventer. rotating head. single ram type preventer with one set of rams, either blank or for pipe, as operator prefers. double ram type preventer with two sets of rams, positioned in accordance with operator’s choice. triple ram type preventer with three sets of rams, positioned in accordance with operator’s choice. drilling spool with side outlet connections for choke and kill lines. 1000 psi rated working pressure.

Components are listed reading upward from the uppermost piece of permanent wellhead equipment, or from the bottom of the preventer stack. A blowout preventer stack may be fully identified by a very simple designation, such as: 5M -13 5/8 - SRRA This preventer stack would be rated 5000 psi working pressure, would have throughbore of 13 5/8 inches, and would be arranged as in Fig. C.5. RAM LOCKS Ram type preventers should be equipped with extension hand wheels hydraulic locks.

V4 Rev March 2002

6-1


SPARE PARTS The following recommended minimum blowout preventer spare parts approved for the service intended should be available at each rig: a.

a complete set of drill pipe rams and ram rubbers for each size drill pipe being used,

b.

a complete set of bonnet or door seals for each size and type of ram preventer being used,

c.

plastic packing for blow out preventer secondary seals,

d.

ring gaskets to fit flange connections, and

e.

appropriate spare parts for annular preventers, when used.

PARTS STORAGE When storing blowout preventer metal parts and related equipment, they should be coated with a protective coating to prevent rust. DRILLING SPOOLS While choke and kill lines may be connected to side outlets of the blowout preventers, many operators prefer that these lines be connected to a drilling spool installed below at least one preventer capable of closing on pipe. Utilisation of the blowout preventer side outlet reduces the number of stack connections by eliminating the drilling spool and shortens the overall preventer stack height. The reasons for using a drilling spool are to localise possible erosion in the less expensive spool and to allow additional space between rams to facilitate stripping operations. Drilling spools for blowout preventer stacks should meet the following minimum specifications:

6-2

a.

Have side outlets no smaller than 2" nominal diameter and be flanged, studded, or clamped for API Class 2M, 3M, and 5M. API Class 10M and 15M installations should have a minimum of two side outlets, one 3" and one 2" nominal diameter.

b.

Have a vertical bore diameter at least equal to the maximum bore of the uppermost casinghead.

c.

Have a working pressure rating equal to the rated working pressure of the attached blowout preventer.

V4 Rev March 2002


V4 Rev March 2002

FIG 6.0.1 EXAMPLE BLOWOUT PREVENTER ARRANGEMENTS FOR 2M RATED WORKING PRESSURE SERVICE – SURFACE INSTALLATION

FIG C.4 ARRANGEMENT RS*R FIG C.2 ARRANGEMENT S*RR Double Ram Preventers, Rd Optional. FIG C.1 ARRANGEMENT S*A

FIG C.3 ARRANGEMENT S*RR

R S* S* S*

S* R R A

R

A

R

For drilling operations, wellhead outlets should not be employed for choke or kill lines Such outlets may be employed for auxiliary or back-up connections to be used only if a failure of the primary control system is experienced.

6-3


A

A

R

R

R

S*

S*

R

FIG C.5 ARRANGEMENT S*RRA Double Ram Type Preventers, Rd Optional.

FIG C.6 ARRANGEMENT RS*RA

FIG 6.0.2 EXAMPLE BLOWOUT PREVENTER ARRANGEMENTS FOR 3M AND 5M RATED WORKING PRESSURE SERVICE – SURFACE INSTALLATION * Drilling spool and its location in the stack arrangement is optional

6-4

V4 Rev March 2002


G**

A**

A**

A**

R

R

R

R

R

R

S*

R

S*

R

S*

R

CASING SPOOL

CASING SPOOL

CASING SPOOL

FIG C.7 ARRANGEMENT RS*RRA** Double Ram Type Preventers, Rd Optional.

FIG C.8 ARRANGEMENT S*RRRA** Double Ram Type Preventers, Rd Optional.

FIG C.9 ARRANGEMENT RS*RRA**G** Double Ram Type Preventers, Rd Optional.

FIG 6.0.3 EXAMPLE BLOWOUT PREVENTER ARRANGEMENTS FOR 10M AND 15M WORKING PRESSURE SERVICE – SURFACE INSTALLATION * Drilling spool and its location in the stack arrangement is optional. ** Annular Preventer A, and rotating head G, can be of a lower pressure rating.

V4 Rev March 2002

6-5


BLOWOUT PREVENTER STACK ARRANGEMENTS SUBSEA INSTALLATIONS VARIANCE FROM SURFACE INSTALLATIONS The arrangements of subsea blowout preventer stacks are similar to the example preventer surface installations with certain differences. The differences are: a.

Choke and kill lines normally are connected to ram preventer body outlets.

b.

Spools may be used to space preventers for shearing tubulars, hanging off drill pipe, or stripping operations.

c.

Choke and kill lines are manifolded for dual purpose usage.

d.

Blind/shear rams are normally used in place of blind rams.

e.

Ram preventers are usually equipped with an integral or remotely operated locking system.

STACK COMPONENT CODES The recommended component codes adopted for designation of subsea blowout preventer stack arrangements use the same nomenclature as surface installations with the addition of remotely operated connectors: CH =remotely operated connector used to attach wellhead or preventers to each other (connector should have a minimum working pressure rating equal to the preventer stack working pressure rating). C = low pressure remotely operated connector used to attach the marine riser to L the blowout preventer stack. Example subsea blowout preventer stack arrangements are illustrated in Figs. D.1 through D.8.

6-6

V4 Rev March 2002

V4 Rev March 2002 FIG D.3 ARRANGEMENT HRRACL Double Ram Type Preventers, Rd, Optional.

CH FIG D.2 ARRANGEMENT HRACL

CH

FIG D.1 ARRANGEMENT CHSACL (2m rated working pressure only.)

FIG 6.0.4 EXAMPLE BLOWOUT PREVENTER ARRANGEMENTS FOR 2M AND 3M RATED WORKING PRESSURE SERVICE – SUBSEA INSTALLATION

CH

FIG D.4 ARRANGEMENT CHRRCHA Double Ram Type Preventers, Rd, Optional.

CH

R

R

R

S

R

CH

A*

R

A

A

A

CL

CL

CL


6-7

6-8 FIG D.7 ARRANGEMENT HRdRdA*CL

R

R R

CH FIG D.6 ARRANGEMENT HRdRA*CHA*

R

R

R

CH

FIG D.5 ARRANGEMENT CHRdRA*CL Triple Ram Type Preventers, Rd Optional

fig 6.0.5 EXAMPLE BLOWOUT PREVENTER ARRANGEMENTS FOR 5M, 10M AND 15M RATED WORKING PRESSURE SERVICE – SUBSEA INSTALLATION

CH

R

R

R

R

A*

A*

A*

CH

CL

CL

A*

FIG D.8 ARRANGEMENT CHRdRdA*CHA*

CH

R

R

R

R

A*

CH

A* WELL CONTROL for the Rig-Site Drilling Team

SECTION 6 : WELL CONTROL EQUIPMENT

V4 Rev March 2002


FIG 6.1.1 U Blowout Preventer


V4 Rev March 2002

6-9


6.1 RAM BLOWOUT PREVENTERS - CAMERON U BOP The Cameron U BOP is the most widely used ram-type BOP for land, platform and subsea applications worldwide and offers the widest range of sizes of any Cameron ram-type BOP. Like all other Cameron preventers, the rams in the U BOP are pressure-energized. Wellbore pressure acts on the rams to increase the sealing force and maintain the seal in case of hydraulic pressure loss. Seal integrity is actually improved by increased well bore pressure. Other features of the U BOP include: •

Hydraulic stud tensioning available on larger sizes to ensure that stud loading is consistently accurate and even.

•

Bonnet seal carrier is available to eliminate the need for high makeup torque on bonnet studs and nuts.

•

Hydraulically operated locking mechanisms, wedgelocks, lock the ram hydraulically and hold the rams mechanically closed even when actuating pressure is released. The operating system can be interlocked using sequence caps to ensure that the wedgelock is retracted before pressure is applied to open the BOP.

•

For subsea applications, a pressure balance chamber is used with the wedge locks to eliminate the possibility of the wedgelock becoming unlocked due to hydrostatic pressure.

Other features include hydraulically opening bonnets, forged body and a wide selection of rams to meet all applications.

Figure 6.1.2 U Blowout Preventer Wedgelock Assembly

6 - 10

V4 Rev March 2002

V4 Rev March 2002

Lo H ck Bon Lo ou in s g net ck in Sc in g, g re Sc w re w

Pi st on ,R am C ha ng e

R am s

S C ea on l R ne in ct gs in , g R od

As se m bl y

In C te yl rm in ed de ia r, te R am Fl an C ge ha ng e

'O 'R Pl in as gs tic Li , C O p In pe ylin Se je Pi ct ra d al er st io t ,O i ng , O on n pe Po ,O C p e ra y rt pe lin ra tin de tin ra g g tin r Pi g st on Bo dy ,

Si de

En try

Bo nn et Se al Si s ng le

Po rt

Bo nn et Se al

G ro ov e


Figure 6.1.3 Figure Cameron U - Type BOP

6 - 11


PIPE RAMS Cameron pipe rams are available for use in Cameron ram-type BOPs to fit all commonly used sizes of tubing, drill pipe, drill collar or casing. •

Cameron pipe rams are self-feeding and incorporate a large reservoir of packer rubber to ensure a long-lasting seal under all conditions.

•

Ram packers lock into place and are not dislodged by well flow

•

All Cameron pipe rams are suitable for H2S service per NACE MR-01-75.

•

CAMRAM™ top seals are standard for all Cameron pipe rams (except U BOPs larger than 13-3/4”).

•

CAMRAM 350™ packers and top seals are available for high temperature service and for service in which concentrations of H2S are expected.

Top Seal

Top Seal

Packer Ram

Ram

U BOP Pipe Ram

Packer

U II BOP Pipe Ram

CAMRAM Top Seal CAMRAM Packer

Ram

Wear Pads

T BOP Pipe Ram

Figure 6.1.4 - PIPE RAMS

6 - 12

V4 Rev March 2002


VARIABLE BORE RAMS One set of Cameron variable bore rams (VBRs) seals on several sizes of pipe or hexagonal kelly, eliminating the need for a set of pipe rams for each pipe size. Features include: •

VBR packer contains steel reinforcing inserts which rotate inward when the rams are closed so the steel provides support for the rubber which seals against the pipe.

•

All VBRs are suitable for H2S service per NACE MR-01-75.

•

CAMRAM™ top seals are standard for all Cameron VBRs.

Top Seal

Ram Body

CAMRAM Packer Ram Body CAMRAM Packer

VBR Packer U and U II BOP Variable Bore Ram

Wear Pads T BOP Variable Bore Ram

Figure 6.1.5 - VBR'S

Shearing Blind Rams Cameron shearing blind rams (SBRs) shear the pipe in the hole, then bend the lower section of sheared pipe to allow the rams to close and seal. SBRs can be used as blind rams during normal drilling operations. Features include: •

Large frontal area on the blade face seal reduces pressure on the rubber and increases service life.

•

Cameron SBRs can cut pipe numerous times without damage to the cutting edge.

•

The single-piece body incorporates an integrated cutting edge.

•

CAMRAM™ top seals are standard for all Cameron SBRs.

•

H2S SBRs are available for critical service applications and include a blade material of hardened high alloy suitable for H2S service.

V4 Rev March 2002

6 - 13


DVS rams are shearing blind rams which are similar to SBRs with the following features: •

DVS (double V shear) rams fold the lower portion of the tubular over after shearing so that the lower blade can seal against the blade packer

•

DVS rams include the largest blade width available to fit within existing ram bores.

CAMRAM Top Seal Ram Body Slide Packer

Blade Packer

CAMRAM Top Seal

Upper SBR

Lower SBR

Blade Insert Slide Packer

U and U ll BOP Shearing Blind Ram

Blade Packer

Blade Insert Lower SBR CAMRAM Top Seal

Blade Packer Upper Blade Insert

Upper SBR

U and U ll H S BOP Shearing Blind Ram 2

Screw

Slide Packer

Lower Blade Insert Lower SBR T BOP Shearing Blind Ram

Wear Pads Upper SBR

Top Seal Upper Ram Body Lower Ram Body

Side Packer

Blade Packer

DVS Shear Ram

Figure 6.1.6 - SHEAR RAMS 6 - 14

V4 Rev March 2002


SECONDARY SEAL The secondary seal is activated by screwing down on the piston which forces plastic through the check valve and into the space between the two swab cup seals. Further piston displacement causes pressure to build up between the swab cups, forcing them to flare out and provide a seal. When the pressure exerted by the plastic packing reaches the proper valve, additional displacement of the piston will overcome the spring tension in the relief valve and plastic packing will begin to extrude from it. The secondary seal should be activated only if the primary connecting-rod seal leaks during and emergency operation. The secondary seal is designed for static conditions and movement of the connecting rod causes rapid seal and rod wear. PROTECTOR PACKING PISTON PLASTIC PACKING CHECK VALVE

RAM SIDE

PRIMARY SEAL SECONDARY SEALS PACKING REGULATOR VALVE

Figure 6.1.7 - SECONDARY SEAL V4 Rev March 2002

6 - 15


U II Blowout Preventer The Cameron U II BOP takes all of the features of the U BOP and adapts them for subsea use in the 18-3/4-10,000 and 15,000 psi WP sizes. Like all other Cameron preventers, the rams in the U II BOP are pressureenergized. Wellbore pressure acts on the rams to increase the sealing force and maintain the seal in case of hydraulic pressure loss. Seal integrity is actually improved by increased well bore pressure. Other features of the U II BOP include: •

Internally ported hydraulic stud tensioning system ensures that stud loading is consistently accurate and even.

•

Bonnet seal carrier is available to eliminate the need for high makeup torque on bonnet studs and nuts.

•

Hydraulically operated locking mechanisms, wedgelocks, lock the ram hydraulically and hold the rams mechanically closed even when actuating pressure is released. The operating system can be interlocked using sequence caps to ensure that the wedgelock is retracted before pressure is applied to open the BOP

•

A pressure balance chamber is used with the wedgelocks to eliminate the possibility of the wedgelock becoming unlocked due to hydrostatic pressure. Other features include hydraulically opening bonnets, forged body and a wide selection of rams to meet all applications.

Figure 6.1.8 - 18-3/4" DOUBLE U II BLOWOUT PREVENTER 6 - 16

V4 Rev March 2002


Optional Equipment Bonnet Seal Carriers for TL, U, UL and U 11 BOPS The bonnet seal carrier is a bore-type sealing assembly which replaces the face seal used as the previous bonnet seal. Sealing capability is not dependent upon bonnet bolt torque. One seal is captured in a machined bore in the BOP body while the other seal is captured in a machined bore in the intermediate flange. The seal carrier was designed, developed and performance-verified for use in newly manufactured BOPs or as a replacement seal assembly for BOPs where either the BOP body or the intermediate flange requires weld repair on the sealing surfaces.

Large Bore Shear Bonnets Cameron developed large bore shear bonnets to increase the available shearing force required to shear high strength and high quality pipe. In order to achieve this the large bore shear bonnet design increased the available closing area by 35% or more. Cameron recommends large bore shear bonnets when larger shearing forces are required. As an alternative to purchasing new large bore shear bonnets, some old shear bonnets can be converted. This process requires reworking and replacing several existing components. Tandem Boosters for U BOPS A BOP equipped with tandem boosters can deliver increased shearing force while not increasing the wear and tear on the packers. Tandem boosters approximately double the force available to shear pipe. Since the tail rod of the tandem booster has the same stroke as the BOP operating piston, the standard shear locking mechanism can be installed on the outside end of the booster.

Large Bore Shear Bonnet Assembly Exploded View

Figure 6.1.9 V4 Rev March 2002

Tandem Booster Exploded View 6 - 17


Figure 6.1.10 UII BOP Hydraulic Control System

6 - 18

V4 Rev March 2002


Figure 6.1.11 UII BOP Part Numbers

V4 Rev March 2002

6 - 19


SHAFFER SL RAM BLOWOUT PREVENTERS Shaffer Model SL ram blowout preventers are the product of more than 50 years of experience in building ram BOP’s to meet the changing demands of the petroleum industry. SL designated models incorporate the improvements made in the LW S preventer line over the past 20 years—improvements resulting from a continuing research program to ensure that Shaffer preventers meet or surpass the latest industry requirements. Special Features

6 - 20

•

Flat doors simplify ram changes. To change the rams, apply opening hydraulic pressure to move the rams to the full open position. Remove the door cap screws and swing the door open. Remove the ram from the ram shaft and replace it. It is not necessary to apply closing hydraulic pressure to move the rams inward to clear the door.

•

Door seals on most sizes have a hard backing moulded into the rubber. This fabric and phenolic backing prevents extrusion and pinching at all pressures to assure long seal life.

•

Internal H2S trim is standard. All major components conform to API and NACE H2S requirements.

•

Maximum ram hardness Is Rc22 to insure H2S compatibility of pipe and blind rams. Shear rams have some harder components.

•

Manual-lock and Poslock pistons can be interchanged on the same door by replacing the ram shaft, piston assembly and cylinder head.

•

Wear rings eliminate metal-to-metal contact between the piston and cylinder to increase seal life d virtually eliminate cylinder bore wear.

•

Lip type piston seals are long-wearing polyurethane with molybdenum disulfide moulded in for lifetime lubrication..

•

Lip-type ram shaft seals hold the well bore pressure and the opening hydraulic pressure. No known failures of this highly reliable high pressure seal have occurred.

•

Secondary ram shaft seals permit injection of plastic packing if the primary lip-type seal ever fails. Fluid dripping from the weep hole in the door indicates that the primary seal is leaking and the secondary seal should be energised.

V4 Rev March 2002


•

Rams are available which will support a 600,000 pounds when a tool joint is lowered onto the closed rams. These rams conform to H2S requirements.

•

Shear rams cut drill pipe and seal in one operation. Most common weights and grades of drill pipe are sheared with less than 1,500 psi hydraulic pressure.

•

Poslock operators automatically lock the rams each time they are closed. This eliminates the cost of a second hydraulic function to lock. It also simplifies emergency operation because the rams are both closed and locked just by activating the close function.

Figure 6.1.12 - SHAFFER SL-RAM BOP

Ram shaft seal Roundhead ram shaft Piston seals Cylinder Weep hole

Flat door Cylinder head

V4 Rev March 2002

Ram Wear rings Piston assembly Secondary ram shaft seal

Ram shaft packing retainer

6 - 21


Figure 6.1.13 - LOCKING SYSTEMS Poslock adjustment thread

Piston

Locking segment

Locking shoulder Ram shaft

Ram

1) Poslock in open position

Cylinder

Piston

Locking segment

Locking cone

2) Poslock piston in closed position

Ram shaft

Ram

1) Manual-lock piston in open position

Cylinder Head

3) Manual-lock piston in closed position

Locking shaft 2) Manual-lock piston in closed and locked position

6 - 22

V4 Rev March 2002


MODEL SL MANUAL-LOCK SYSTEM Manual-lock pistons move inward and close the rams when closing hydraulic pressure is applied. If desired, the rams can be manually locked in the closed position by turning each locking shaft to the right until it shoulders against the cylinder head. Should hydraulic pressure fail, the rams can be manually closed and locked. They cannot be manually reopened. The manual locking shafts are visible from outside and provide a convenient ram position indicator. Threads on the manual locking shaft are enclosed in the hydraulic fluid and are not exposed to corrosion from mud and salt water or to freezing. Rams are opened by first turning both locking shafts to their “unlocked” position, then applying opening hydraulic pressure to the pistons, which move outward and pull the rams out of the well bore. MODEL SL HYDRAULIC SYSTEM OPERATION AND MAINTENANCE Hydraulic power to operate a Model SL ram BOP can be furnished by any standard oil field accumulator system. Hydraulic passages drilled through the body eliminate the need for external manifold pipes between the hinges. Each set of rams requires only one opening and one closing line. There are two opening and two closing hydraulic ports, clearly marked, on the back side of the BOP. The extra hydraulic ports facilitate connecting the control system to the preventer. A 1,500-psi-output hydraulic accumulator will close any Model SL ram BOP with rated working pressure in the well bore except for the 11" and 13 5/8—15,000 psi BOP’s, which require 2,100 psi. However, these two will close against 10,000 psi well pressure with less than 1,500 psi hydraulic pressure. A 3,000 psi hydraulic pressure may be used, but this will accelerate wear of the piston seals and the ram rubbers. A 5,000 psi hydraulic pressure test is applied to all Model SL cylinders at the factory. However, it is recommended that this pressure not be used in the field application.

V4 Rev March 2002

6 - 23


The hydraulic operating fluid should be hydraulic oil with a viscosity between 200 and 300 SSU at 100°F. If necessary, a water-soluble oil such as NL Rig Equipment K-90 and water can be used for environmental protection. Ethylene glycol must be added to the K-90 and water solution for freeze protection if equipment is exposed to freezing temperatures. NOTE: Never use fuel oil of any kind as it causes the rubber goods to swell and deteriorate. Some water-soluble fluids do not give adequate corrosion protection or lubrication and should not be used.

MODEL SL POSLOCK SYSTEM SL preventers equipped with Poslock pistons are automatically locked in the closed position each time they are closed. The preventers will remain locked in the closed position even if closing pressure is removed. Opening hydraulic pressure is required to reopen the pistons. The hydraulics required to operate the Poslock are provided through opening and closing operating ports. Operation of the Poslock requires no additional hydraulic functions, such as are required in some competitive ram locking systems. When closing hydraulic pressure is applied, the complete piston assembly moves inward and pushes the rams into the well bore. As the piston reaches the’ fully closed position, the locking segments slide toward the piston O.D. over the locking shoulder as the locking cone is forced inward by the closing hydraulic pressure. The locking cone holds the locking segments in position and is prevented by a spring from vibrating outward if the hydraulic closing pressure is removed. Actually, the locking cone is a second piston inside the main piston. It is forced inward by closing hydraulic pressure and outward by opening hydraulic pressure. When opening hydraulic pressure is applied, the locking cone moves outward and the locking segments slide toward the piston l.D. along the tapered locking shoulder. The piston is then free to move outward and open the rams. NOTE: Poslock pistons are adjusted in the factory and normally do not require adjustment in the field except when changing between pipe rams and shear rams. The adjustment is easy to check and easy to change.

6 - 24

V4 Rev March 2002


Figure 6.1.14 - FLUID CIRCUIT - SL RAM


V4 Rev March 2002

6 - 25


ULTRALOCK™ LOCKING SYSTEM UltraLock, the most versatile locking system available, provides a maintenancefree and adjustment-free locking system that is compatible with any ram assembly that the blowout preventers can accommodate. Once the UltraLock is installed, no further adjustments will be needed when changing between Pipe Rams, Blind/ Shear or MULTI-RAM assemblies. BOPs that are equipped with the UltraLock are automatically locked in the closed position each time the BOPs are closed; no preset pressure ranges are needed. The BOPs will remain locked in the closed position, even if closing pressure is lost or removed. Hydraulic opening pressure is required to re-open the preventer, and this opening pressure is supplied by the regular opening and closing ports of the preventer. No additional hydraulic lines or functions are required for operations of the locks. Stack frame modifications are not required because all operational components are in the hydraulic operating cylinders. Existing BOPs with PosLock~ Cylinders can be upgraded to the UltraLock. U.S. patent number 5,025,708. Secondary Unlocking Piston Locking Plate

Locking Rod Plate Retaining Screw

Locking Ram Load Ultra Lock Shaft Dog Piston Spring Locking Dog Retainer

Locking Rod

Locking Rod Plate

Figure 6.1.15 - ULTRALOCK - UNIQUE POSITION LOCKING SYSTEM 6 - 26

V4 Rev March 2002


TYPE 72 SHEAR RAMS Type 72 shear rams shear pipe and seal the well bore in one operation. They also function as blind or CSO (complete shut-off) rams for normal operations. The hydraulic closing pressure required to shear commonly used drill pipe is below 1,500 psi for BOP’s with 14'’ pistons. These pistons are standard in all BOP’s rated at 10,000 psi working pressure and higher. On lower pressure preventers, optional 14" pistons can be supplied for shearing instead of the standard 10" pistons. When shearing, the lower blade passes below the sharp lower edge of the upper ram block and shears the pipe. The lower section of cut pipe is accommodated in the space between the lower blade and the upper holder. The upper section of cut pipe is accommodated in the recess in the top of the lower ram block. Closing motion of the rams continues until the ram block ends meet. Continued closing of the holders squeezes the semicircular seals upward into sealing contact with the seat in the BOP body and energises the horizontal seal. The closing motion of the upper holder pushes the horizontal seal forward and downward on top of the lower blade, resulting in a tight sealing contact. The horizontal seal has a moulded-in support plate which holds it in place when the rams are open. Type 72 Shear Rams are covered by U.S. Patent No. 3,736,982. (Ref fig 6.1.16)

V4 Rev March 2002

6 - 27


UPPER RUBBER

LOWER RUBBER

LOWER BLOCK

UPPER BLOCK

LOWER HOLDER

SHEAR BLADE UPPER HOLDER

HORIZONRAL SEAL

SEMICIRCULAR SEAL

SUPPORT PLATE

SHEAR RAMS OPEN

SHEAR RAMS CLOSING

HORIZONRAL SEAL

SEMICIRCULAR SEAL

SUPPORT PLATE

SHEAR RAMS CLOSED

Figure 6.1.16 - TYPE 72 SHEAR RAMS 6 - 28

V4 Rev March 2002


HYDRIL RAM BLOWOUT PREVENTERS Features: (Refer to Fig 6.1.17 and 6.1.18) 1. The Ram Body Casting has controlled and predictable structural hardness and strength throughout the pressure vessel. Hydril pressure vessel material has equal strength along all axes to provide reliable strength and resistance to sulphide stress cracking in hydrogen sulphide service. 2. The Ram Assembly provides reliable seal off of the wellbore for security and safety. The Ram accommodates a large volume of feedable rubber in the front packer and upper seal for long service life. 3. The Field Replaceable Seal Seat provides a smooth sealing surface for the ram upper seal. The seal seat utilises specially selected and performance effective materials for maximum service life. 4 Hinged Bonnet swing completely clear of overhead restrictions (such as another BOP) and provide easy access for rapid ram change to reduce downtime. 5. Load Hinges separate from the fluid hinge and are equipped with selflubricated bearings to support the full weight of the bonnet for quick and easy opening of the bonnet. 6. Fluid Hinges, separate from the load hinges, connect the control fluid passages between the body and bonnets. This arrangement provides a reliable hydraulic seal and permits full pressure testing and ram operation with the bonnets open. The fluid hinges and bonnet hinges contain all the seals necessary for this function and may be removed rapidly for simple, economical repair. 7. Replaceable Cylinder Liner has a corrosion and wear resistant bore for reliable piston operation. The cylinder liner is easily field replaceable or reparable for reduced maintenance cost and downtime. 8. Piston and Piston Rod Assembly are one piece for strength and reliability in closing and opening the ram which results in a secure operating assembly. 9. Choice of Ram Locks—Automatic Multiple Position Locking (MPL) or Manual Locking is available on Ram BOPs. 10. Multiple-Position Locking (MPL) utilises a hydraulically-actuated mechanical clutch mechanism to automatically lock the rams in a seal off position. 11. Manual Locking utilises a heavy-duty acme thread to manually lock the ram in a sealed-off position or to manually close the ram if the hydraulic system is inoperative. 12. Fluid Connections and Hydraulic Passages are internal to the bonnets and body and preclude damage during moving and handling operations. V4 Rev March 2002

6 - 29


13. Connector Ring Grooves are stainless steel lined for all connectors (top, bottom and side outlets) for corrosion resistance of the sealing surface. 14. Sloped Ram Cavity is self-draining to eliminate build-up of sand and drilling fluid. 15. Bonnet Seal utilises field proven material in an integrated seal design which combines the seal and backup ring for reliability and long life. 16. Piston Rod Mud Seal is a rugged, field-proven, integrally designed lip seal and backup ring retained in the bonnet by a stainless steel spiral lock ring. 17. Secondary (Emergency) Piston Rod Packing provides an emergency piston rod seal for use in the event of primary seal leakage at a time when repair cannot be immediately effected. 18. A Weephole to atmosphere isolates wellbore pressure, indicates when seal is achieved and possible leakage in the primary seat. (Shown out of position) 19. Piston Seals are of a lip-type design and are pressure-energized to provide a reliable seal of the piston to form the operating chambers of the BOP. 20. Side Outlets for choke/kill lines are available on all models. Two outlets, one on each side, may be placed below each ram. In single and double configurations, outlets may be placed below the upper and lower ram, below the bottom ram only, or below the top ram only, therefore providing great versatility in stack design. 21. Single and Double Configurations are available with a choice of American Petroleum Institute (API) flanged, studded or clamp hub connections. This allows for the most-economical use of space for operation and service. (Not shown) 22. Bonnet Bolts are sized for easy torquing and arranged for reliable seal between bonnet and body. This prevents excessive distortion during high pressure seal off. 23. Bonnet Bolt Retainers keep the bonnet bolts in the bonnet while servicing the BOP. 24. Guide Rods align ram with bonnet cavity, preventing damage to the ram, piston rod or bonnets while retracting the rams. 25. Ram Seal Off is retained by wellbore pressures. Closing forces are not required to retain an established ram seal off.

6 - 30

V4 Rev March 2002

V4 Rev March 2002

11. MANUAL LOCKING

22. BONNET BOLTS

7. REPLACABLE CYLINDER LINER

14. SLOPED RAM CAVITY 16. PISTON ROD MUD SEAL 18. A WEEPHOLE

24. GUIDE RODS

5. LOAN HINGES

6. FLUID HINGES

20. SLIDE OUTLETS FOR CHOKE/KILL

12. FLUID CONNECTIONS AND HYDRAULIC PASSAGES

1. THE RAM BODY CASTING

Figure 6.1.17 - 13 5/8" - 10,000 PSI RAM BOP MANUAL LOCK

19. PISTON SEALS

17. SECONDARY (EMERGENCY) (PISTON ROD PACKING)

2. THE RAM ASSEMBLY

15. BONNET SEAL

3. THE FIELD REPLACABLE SEAL SEAT

13. CONNECTOR RING GROOVES


6 - 31

6 - 32

7. REPLACEABLE CYLINDER LINER

14. SLOPED RAM CAVITY

20. SIDE OUTLETS FOR CHOKE KILL

1. THE RAM BODY CASTING

13. CONNECTOR RING GROOVES

16. PISTON ROD MUD SEAL 18. A WEEPHOLE 19. PISTON SEALS

15. BONNET SEAL

3. THE FIELD REPLACEABLE SEAL SEAT

Figure 6.1.18 - 18 3/4" - 15,000 PSI RAM BOP MULTIPLE POSITION LOCK (MPL)

8. PISTON AND PISTON ROD ASSEMBLY

10. MULTIPLE-POSITION LOCKING (MPL)

5. LOAD HINGES

6. FLUID HINGES

22. BONNET BOLTS

2. THE RAM ASSEMBLY



V4 Rev March 2002


MPL AUTOMATIC RAM LOCKING (Refer to Fig 6.1.19) Hydril Ram Blowout Preventers are available with automatic Multiple-Position Ram Locking. Multiple-Position Locking (MPL) allows the ram to seal off with optimum seal squeeze at every closure. MPL automatically locks and maintains the ram closed with the optimum rubber pressure required for seal off in the front packer and upper seal. Front packer seal wear (on any ram BOP) requires a different ram locking position with each closure to ensure an effective seal off. Multiple-Position Locking is required to ensure retention of that seal off position. A mechanical lock is automatically set each time the ram is closed. Ram closure is accomplished by applying hydraulic pressure to the closing chamber which moves the ram to a seal off position. The locking system maintains the ram mechanically locked while closure is retained and/or after releasing closing pressure. The ram is opened only by application of opening pressure which releases the locking system automatically and opens the ram, simultaneously. MPL is available on all Hydril Ram Blowout Preventers. How MPL works This figure shows the ram maintained closed and sealed off by the MPL. Hydraulic closing pressure has been released. The Hydril Ram Blowout Preventer with MPL automatically maintains ram closure and seal off. MPL will maintain the required rubber pressure in the front packer and upper seal to ensure a seal off of rating working pressure. MPL will maintain the seal off without closing pressure and with the opening forces created by hanging the drill string on the ram. Locking and unlocking of the MPL are controlled by a unidirectional clutch mechanism and a lock nut. The unidirectional clutch mechanism maintains the nut and ram in a locked position until the clutch is disengaged by application of control system pressure to open the ram. Hydraulic opening pressure disengages the front and rear clutch plates to permit the lock nut to rotate and the ram to open. As the ram and piston move to the open position, the lock nut and front clutch plate rotate freely.

V4 Rev March 2002

6 - 33


Figure 6.1.19 - HYDRILL MULTI-POSITION LOCK (MPL) 6 - 34

V4 Rev March 2002


Figure 6.1.20 Ram Preventer Opening and Close Ratios Cameron U SIZE

7 1/16 in.

9 in.

11 in.

WP (psi)

3,000 5,000 10,000 15,000

Open

Close

2.3 2.3 2.3 2.3

6.9 6.9 6.9 6.9

Shaffer 'SL' Open

3.37

Hydril Ram

Close

Open

Close

7.11

1.5 1.5 1.7 6.6

5.4 5.4 8.2 7.6

2.6 2.6

5.3 5.3

6.8 6.8 7.6 7.6

2,000 3,000 5,000 10,000 2,000 3,000 5,000 10,000 15,000

2.5 2.5 2.5 2.5 2.2

7.3 7.3 7.3 7.3 9.9

7.62 2.8

7.11 7.11

2.0 2.0 2.4 3.24

13 5/8 in.

3,000 5,000 10,000 15,000

2.3 2.3 2.3 5.6

7.0 7.0 7.0 8.4

3.00 3.00 4.29 2.14

5.54 5.54 7.11 7.11

2.1 2.1 3.8 3.56

5.2 5.2 10.6 7.74

16 3/4 in.

2,000 3,000 5,000 10,000

2.3 2.3 2.3

6.8 6.8 6.8

2.03 2.06

5.54 7.11

2.41

10.6

18 3/4 in.

10,000 15,000

3.6 4.1

7.4 9.7

1.83 1.68

7.11 10.85

1.9 2.15

10.6 7.27

21 1/4 in.

2,000 3,000 5,000 10,000

1.3 1.3 5.1 4.1

7.0 7.0 6.2 7.2

0.98 0.98 1.9

5.2 5.2 10.6

2,000 3,000

1.0

7.0

26 3/4 in.

V4 Rev March 2002

1.63

7.11

6 - 35


EXAMPLE CLOSING FORCES IN RELATION TO AREA a) When closing the well in on a floating rig the hard shut in method is usually applied. The string is picked up say 20’ off bottom, the rotary table or top drive is shut off and both pumps are shut down. The annular preventer is then closed and the fail-safe's opened against a closed choke. b)

The tool joint is then spaced out for the correct pipe rams.

c) The string is stripped down until the tool joint is "hung off’ on the rams. The correct operating pressure to set on the manifold regulator is directly related to the well bore pressure. For example. Operating ratio 10:56:1. Working pressure of BOP stack 10,000 psi. F P = ––– A

∴F=PxA

10,000 psi ––––––––– = 947 psi 10.56

This pressure does not include an allowance for friction losses so the minimum pressure would be say 1000 psi : 1000 psi x 10.56 = 10560 lbs closing force. Figure 6.1.21

RAM SHAFT AREA

➙

➙ 6 - 36

➙

➙

➙➙ ➙➙

➙➙ CLOSING ➙ ➙ AREA

➙➙ ➙➙

CLOSING PRESSURE

V4 Rev March 2002


Figure 6.1.22 RAM PREVENTERS -FLUID REQUIRED TO OPERATE

V4 Rev March 2002

6 - 37


6.2 ANNULAR PREVENTERS In the unique design of the Cameron DL annular BOP, closing pressure forces the operating piston and pusher plate upward to displace the solid elastomer donut and force the packer to close inward. As the packer closes, steel reinforcing inserts rotate inward to form a continuous support ring of steel at the top and bottom of the packer. The inserts remain in contact with each other whether the packer is open, closed on pipe or closed on open hole. Other features of the DL BOP include: • The Cameron DL BOP is shorter in height than comparable annular preventers. A quick-release top with a one-piece split lock ring permits quick packer change out with no loose parts involved. The design also provides visual indication of whether the top is locked or unlocked. • The DL BOP is designed to simplify field maintenance. Components subject to wear are field-replaceable and the entire operating system may be removed in the field for immediate change-out without removing the BOP from the stack. • Twin seals separated by a vented chamber positively isolate the BOP operating system from well bore pressure. High strength polymer bearing rings prevent metal-to-metal contact and reduce wear between all moving parts of the operating systems. • Packers for DL BOPs have the capacity to strip pipe as well as close and seal on almost any size or shape object that will fit into the wellbore. These packers will also close and seal on open hole. Some annular packers can also be split for installation while pipe is in the hole. Popular sizes of the DL BOP are available with high-performance CAMULAR™ annular packing subassemblies.

ACCESS FLAPS

PACKING UNIT CONSISTING OF: PACKER, DONUT

LOCKING GROOVES

PUSHER PLATE

OPENING CHAMBER PISTON

OPENING HYDRAULIC PORT

CLOSING HYDRAULIC PORTS

VENT

Figure 6.2.1 DL ANNULAR BLOWOUT PREVENTER 6 - 38

V4 Rev March 2002


Figure 6.2.2 CAMERON 20,000 PSI WP ANNULAR BLOWOUT PREVENTER SEALING ELEMENT

OPEN

V4 Rev March 2002

CLOSED ON PIPE

CLOSED ON OPEN HOLE

6 - 39


Figure 6.2.3 HYDRIL “GK” ANNULAR


6 - 40

V4 Rev March 2002


OPERATIONAL FEATURES The Hydril GK Annular BOPs are particularly qualified to meet the industry’s needs for simple and reliable blowout protection. Over 40 years of operational experience provide the simplest, field proven mechanism in the industry. Only Two Moving Parts (piston and packing unit) on the Hydril Annular BOP mean few areas are subjected to wear. The BOP is thus a safer, and more efficient mechanism requiring less maintenance and downtime. A Long piston with a length to diameter ratio approaching one eliminates tendencies to cock and bind during operations with off-centre pipe or unevenly distributed accumulation of sand, cuttings, or other elements. This design ensures the packing unit will always reopen to full bore position. Back to Front Feedable Rubber on the Packing Unit enables the packing unit to close and seal on virtually any shape in the drillstring or completely shut off the open bore and to strip tool joints under pressure. This feature permits confident closure of the BOP at the initial indication of a “kick” without delaying to locate the tool joint. The Conical Bowl Design of the Piston provides a simple and efficient method of closing the packing unit. The piston serves as a sealing surface against the rubber packing unit; there is no metal-to-metal wear and thus longer equipment life results. Utilisation of Maximum Packing Unit life is made possible with a piston indicator for measuring piston stroke. This measurement indicates remaining packing unit life and ensures valid testing. A Field Replaceable Wear Plate In the BOP Head serves as an upper non-sealing wear surface for the movement of the packing unit, making field repair fast and economical. Flanged Steel Inserts In the Packing Unit reinforce the rubber and control rubber flow and extrusion for safer operation and longer packing unit life. Greater Stripping Capability is inherent in the design of the packing unit since testing (fatigue) wear occurs on the outside and stripping wear occurs on the inside of the packing unit. Thus, testing wear has virtually no affect on stripping capability and greater overall life of the packing unit results. The resulting ability to strip the drillstring to the bottom without first changing the packing unit means a safer operation, lower operating costs and longer service life for the packing unit. The Packing Unit Is Tested to Full Rated Working Pressure at the factory and the tests are documented— before it reaches the well site—to ensure a safe, quality performance. The Packing Unit Is Replaceable with Pipe In the Bore, which eliminates pulling the drillstring for replacement and reduces operating expenses with more options for well control techniques. Large Pressure Energised Seals are used for dynamically sealing piston chambers to provide safe operation, long seal life, and less maintenance. Piston Sealing Surfaces Protected by Operating Fluid lowers friction and protects against galling and wear to increase seal life and reduce maintenance time. V4 Rev March 2002

6 - 41


BOP CLOSURE SEQUENCE

All Hydril Annular Blowout Preventers employ the same time-tested design for sealing off virtually anything in the BOP bore or the open hole. During normal wellbore operations, the BOP is kept fully open by leaving the piston down. This position permits passage of tools, casing, and other items up to the full bore size of the BOP as well as providing maximum annulus flow of drilling fluids. The BOP is maintained in the open position by application of hydraulic pressure to the opening chamber, this ensures positive control of the piston during drilling and reduces wear caused by vibration. (See Fig 6.2.4/A)

The piston is raised by applying hydraulic pressure to the closing chamber. This raises the piston, which in turn squeezes the steel reinforced packing unit inward to a sealing engagement with the drill string. The closing pressure should be regulated with a separate pressure regulator valve for the annular BOP. Guidelines for closing pressures are contained in the applicable Operator’s Manual. (See Fig 6.2.4/B)

The packing unit is kept in compression throughout the sealing area, thus assuring a tough, v durable seal off against virtually any drill string shape—kelly, tool joint, pipe, or tubing to full rated working pressure. Application of opening chamber pressure returns the piston to the full down position allowing the packing unit to return to full open bore through the natural resiliency of the rubber. (See Fig 6.2.4/C)

6 - 42

V4 Rev March 2002


BOP CLOSURE SEQUENCE

Figure 6.2.4/A - CLOSURE SEQUENCE (OPEN)

Figure 6.2.4/B - CLOSURE SEQUENCE (PART CLOSED)

Figure 6.2.4/C - CLOSURE SEQUENCE (SEALED OFF) V4 Rev March 2002

6 - 43


Figure 6.2.5 Complete shut off (CSO) of the well bore is possible with all Hydril Annular BOP’s. During CSO the flanges of the steel inserts form a solid ring to confine the rubber and provide a safe seal off of the rated working pressure of the BOP. This feature should be utilised only during well control situations, as it will reduce the life of the packing unit. STRIPPING OPERATIONS Drill pipe can be rotated and tool joints stripped through a closed packing unit, while maintaining a full seal on the pipe. Longest packing unit life is obtained by adjusting the closing chamber pressure just low enough to maintain a seal on the drill pipe with a slight amount of drilling fluid leakage as the tool joint passes through the packing unit. This leakage indicates the lowest usable closing pressure for minimum packing unit wear and provides lubrication for the drill pipe motion through the packing unit. The pressure regulator valve should be set to maintain the proper closing chamber pressure. If the pressure regulator valve cannot respond fast enough for effective control, an accumulator (surge absorber) should be installed in the closing chamber control line adjacent to the BOP—precharge the accumulator to 50% of the closing pressure required. In subsea operations, it is sometimes advisable to add an accumulator to the opening chamber line to prevent undesirable pressure variations with certain control system circuits

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V4 Rev March 2002


TYPE GL 5000 PSI ANNULAR BLOWOUT PREVENTERS PATENTED Hydril GL Annular Blowout Preventers are designed and developed both for subsea and surface operations. The GL family of BOPs represents the cumulation of evolutionary design and operator requirements. The proven packing unit provides full closure at maximum working pressure on open hole or on virtually anything in the bore - casing, drill pipe, tool joints, kelly, or tubing. Features of the GL make it particularly desirable for subsea and deep well drilling. These drilling conditions demand long-life packing elements for drill pipe stripping operations and frequent testing. The GL BOP offers the longest life packing unit for annular blowout preventers available in the industry today - especially for the combination of BOP testing and stripping pipe into or out of a well under pressure. The latched head permits quick, positive head removal for packing unit replacement or other maintenance with only minimum time required. The following outstanding features of the Hydril GL BOPs make these units particularly qualified to meet the industry’s needs for simple and reliable blowout protection. The Secondary Chamber, which is unique to the GL BOP, provides this unit with great flexibility of control hookup and acts as a backup closing chamber to cut operating costs and increase safety factors in critical situations. The chamber can be connected four ways to optimise operations for different effects: 1. Minimise closing/opening fluid volumes. 2. Reduce closing pressure. 3. Automatically compensate (counter balance) for marine riser hydrostatic pressure effects in deep water. 4. Operate as a secondary closing chamber. Automatic Counter Balance can be achieved in subsea applications by selection of one of the optional hookups of the secondary chamber. The Latched Head provides fast, positive access to the packing unit and seals for minimum maintenance time. The latching mechanism releases the head with a few turns of the Jaw Operating Screws, while the entire mechanism remains inside the blowout preventer. There are no loose parts to be lost downhole or overboard. The Opening Chamber Head protects the opening chamber and prevents inadvertent contamination of the hydraulic system while the head is removed for packing unit replacement.

V4 Rev March 2002

6 - 45

6 - 46

Figure 6.2.6

Cutaway View of GL BOP shown in Midstroke. 5000 or 10,000 psi bottom connections are available in hub, API flanged, or studded connection.

SECONDARY CHAMBER

CLOSING CHAMBER

OPENING CHAMBER PISTON CHAMBER

OPENING CHAMBER HEAD

LATCHED HEAD

PACKING UNIT

WEAR PLATE

PISTON INDICATOR HOLE



V4 Rev March 2002


Figure 6.2.7 GL 16 3/8" - 5000 PSI BLOWOUT PREVENTER Item No. 1 2 3 4 5 6 7 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 27 29 32 33 34

Part Name

No Req'd Approx. Net Single Weight lb. BOP Assembly 1 28,400 BOP Head 1 6,641 "O" Ring 1 .75 "O" Ring 20 .06 Jaw Operating Screw 20 4 Sleeve Screw 20 .25 Spacer Sleeve 20 .25 Pipe Plug 20 .25 Jaw 20 12 Packing Unit - Natural 1 910 Packing Unit - Synthetic 1 920 Piston 1 5,380 Non-extrusion Ring, Middle 2 3 Double "U" Seal, Middle 1 3 Non-extrusion Ring, Lower 2 2 Double "U" Seal, Lower 1 2.5 Body 1 14,105 "O" Ring 1 .5 Capscrew 14 .75 Slotted Body Sleeve 1 300 Outer Body Sleeve 1 1180 Non-extrusion Ring, Inner 2 1 Double "U" Seal, Inner 1 2.3 Opening Chamber Head 1 839 "U" Seal 2 3 Head Gasket 1 2.5 Pull Down Bolt Assembly 4 1 Relief Fitting 1 .06 Pipe Plug 1 .06 Seal Set - Complete ACCESSORIES Chain Sling Assembly Eye Bolts, Piston (1"-8NC x 17" LG) Eye Bolts, Head (1 1/2"-6NC x 2" LG) Eye Bolts, Opening Chamber Head (7/8"-9NC x 2 1/4" LG) Protector Plate Protector Plate Screw

V4 Rev March 2002

1

202

2

6

3

6.75

3 1 4

1 99 .13

6 - 47

6 - 48

CLOSING PRESSURE

SECONDARY CHAMBER connected to OPENING CHAMBER (S - O)

FIG. 1

Standard surface hook-up requires least fluid so gives a faster closing time.

OPENING PRESSURE

SECONDARY CHAMBER connected to CLOSING CHAMBER (S - C)

FIG. 2

Subsea hook-up for water depths over 800 ft.

SECONDARY CHAMBER connected to MARINE RISER (CB)

FIG. 3

Subsea hook-up for water depths up to 800 ft.

HYDRIL 'GL'



Figure 6.2.8

V4 Rev March 2002


Figure 6.2.9 CONTRACTOR PISTON differential area exposed to mud column

centre line

opening pressure

packing unit

opening area

operating piston

closing area closing pressure

well pressure well pressure area

As the contractor piston is raised by hydraulic pressure, the rubber packing unit is squeezed inward to a sealing engagement with anything suspended in the wellbore. Compression of the rubber throughout the sealing area assured a seal-off against any shape.

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6 - 49


Figure 6.2.10

Average Surface Closing Pressure CLOSING PRESSURE - PSI SECONDARY CHAMBER CONNECTED TO OPENING CHAMBER

(GL-16 3/4-5000 Standard Hook-up) 1500

CSO

1000

3 1/2" thru 7" Pipe

7 5/8" thru 13 3/8" Pipe

500

CAUTION : Due to limiting properties of casing, closure should be done carefully, using initial closing pressure to prevent collapse of casing. The closing pressures shown are initial closing pressures for most casing at O (zero) well pressure. Slightly higher closing pressure may be required for seal-off at higher well pressures.

0

1000

0

2000

3000

NOTE : Pressures shown are average. Actual pressure required to affect seal-off will vary slightly with each individual packing unit.

4000

5000

WELL PRESSURE - PSI

Operating pressure for Subsea Annular Preventers Adjustment Pressure (∆P) =

(0.052 x Wm x Dw) - (0.45 x Dw) ––––––––––––––––––––––––––– p

Where: Wm Dw 0.052 p

= = = =

0.45 psi/ft.

=

drilling fluid density in lb./gal. water depth in feet conversion factor 2.13 = the ratio of closing chamber area to secondary chamber area for GL 16 3/4 - 5000. pressure gradient for sea-water using a specific gravity of sea water = 1.04 and 0.433 psi/ft. pressure gradient for fresh water.

The optimum closing pressure for the standard hookup is obtained using the following formula: Closing Pressure = Surface Closing Pressure + Adjustment Pressure (∆P) 6 - 50

V4 Rev March 2002


Operating Pressure for Accumulator Bottles Example 1 3 1/ " - 7" pipe, 3500 psi well pressure, 16 lb./gal. drilling fluid, 500 ft. water depth. 2 Closing Pressure = Surface Closing Pressure + Adjustment Pressure (∆P) From the Surface Closing Pressure graph Figure 6.5.13: Surface Closing Pressure =

900 psi.

(0.052 x 16 Ib/gal x 500 ft) - (0.45 psi/ft x 500 ft) Adjustment Pressure (∆P) = ––––––––––––––––––––––––––––––––––––– 2. 13 Adjustment Pressure (∆P) =

90 psi

Closing Pressure

900 psi + 90 psi = 990 psi.

=

Pre-Charge Pressures - Surge Bottles The pre-charge pressure for the closing chamber surge absorber can be calculated using the following example: Example 2 1 3 /2" - 7" pipe, 500 feet water depth.

Precharge = 0.80 [Surface Closing Pressure + (0.41 x Dw)] Where: Dw

=

0.41 psi/ft. =

water depth in feet. pressure gradient for control fluid (water and water soluble oil) using a specific gravity of the mixture = 0.95 and 0.433 psi/ft pressure gradient for fresh water.

Surface Closing Pressure = 600 psi. Precharge =

0.80 [600 psi + (0.41 psi/ft. x 500 ft)]

= 644 psi.

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Only packing elements which are supplied by the manufacturer of the annular preventer should be used. New or repaired units obtained from other service companies should not be used since the preventer manufacturers cannot be held responsible for malfunction of their equipment unless their elements are installed. Figure 6.2.11 Packing unit selection (from Hydril) PACKING UNIT TYPE

IDENTIFICATION Colour

Code

OPERATING TEMP RANGE

DRILLING FLUID COMPATIBILITY

NATURAL RUBBER

Black

NR

-30°F – 225°F

Waterbase Fluid

NITRILE RUBBER

Red

NBR Band

20°F – 190°F

Oil base/Oil Additive Fluid

NEOPRENE RUBBER

Green Band

CR

-30°F – 170°F

Oil Base Fluid

Figure 6.2.12 Annular Preventers Gallons of Fluid Required to Operate on Open Hole Size and Working Pressure Inches psi 6 3,000 6 5,000 7 1/16 10,000 8 3,000 8 5,000 10 3,000 10 5,000 11 5,000 11 10,000 12 3,000 13 5/8 3,000 13 5/8 5,000 13 5/8 10,000 16 2,000 16 3,000 16 3/4 3,000 16 3/4 5,000 16 3/4 10,000 18 2,000 18 3/4 5,000 20 2,000 20 3,000 20 5,000 30 1,000 30 2,000

6 - 52

Hydril GK Close 2.9 3.9 9.4 4.4 6.8 7.5 9.8

Open 2.2 3.3

Close

GL Open

Balancing

NL Shaffer Spherical Close Open 4.6 3.2 4.6 3.2

3.0 5.8 5.6 8.0

7.2 11.1 11.0 18.7

5.0 8.7 6.8 14.6

25.1 11.4

9.8

23.5

14.7

18.0 34.5 17.5 21.0

14.2 24.3 12.6 14.8

19.8

19.8

8.2

23.6 47.2

17.4 37.6

28.7

19.9

33.8

33.8

17.3

33.0

25.6

21.1

14.4 44.0

44.0

20.0

48.2 32.6

37.6 17.0

58.0

58.0

29.5

61.4

47.8

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SPHERICAL BLOWOUT PREVENTERS Shaffer Spherical blowout preventers are compact, annular type BOP’s which reliably seal on almost any shape or size—kellys, drill pipe, tool joints, drill collars, casing or wireline. Sphericals also provide positive pressure control for stripping drill pipe into and out of the hole. They are available in bolted cover, wedge cover and dual wedge cover models. There are also special lightweight models for airlifting and Arctic models for low temperature service. Figure 6.2.13 SHAFFER ANNULAR

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6 - 53


OPERATION AND MAINTENANCE INSTALLATION A blowout preventer operating and control system is required to actuate the Spherical BOP. Several systems are available and those commonly used on drilling rigs work well. The recommended installation requires: 1. A control line to the closing (lower) port. 2. For stripping, an accumulator bottle in the closing line adjacent to the BOP. This bottle should be precharged to 500 psi for surface installations and to 500 psi plus 45 psi per 100' of water depth for subsea installations. 3. control line to the opening (upper) port. 4. A hydraulic regulator to allow adjustment of operating pressure to meet any given situation. The hydraulic operating fluid should be hydraulic oil with a viscosity between 200 and 300 SSU at 100°F If necessary, a water-soluble oil such as Koomey K-90 and water can be used for environmental protection. If equipment is exposed to freezing temperatures, ethylene glycol must be added to the K-90 and water solution for freeze protection. NOTE: Some water-soluble systems will corrode the metals used in BOP’s. If water-soluble oil is used, the user should ensure that it provides adequate lubrication and corrosion protection. Accumulator bottle (1-gal. capacity for 1 1/16" - 10,00 psi bolted-cover model; 5-gal. capacity for all other bolted-cover models and 13 5/8"5,000 psi wedge-cover model; 10-gal. capacity for all other wedge-cover models)

Opening line

Hydraulic unit

Closing line

Installation hookup for single Spherical BOP

Accumulator bottles Opening line Closing line Opening line

Closing line Station1 Station 2 Hydraulic unit

Figure 6.2.14 6 - 54

Installation hookup for dual Spherical BOP

V4 Rev March 2002


OPERATION AND MAINTENANCE OPERATING REQUIREMENTS Sphericals have relatively simple operating requirements compared to other annulars. When closing on stationary pipe, 1,500 psi operating pressure is sufficient in most applications. Recommended closing pressures for specific applications are given in the table at the bottom of the page. Closing action begins when hydraulic fluid is pumped into the closing chamber of the Spherical BOP below the piston (upper right). As the piston rises, it pushes the element up, and the element’s spherical shape causes it to close in at the top as it moves upward. The element seals around the drill string as the piston continues to rise (middle right). Steel segments in the element move into the well bore to support the rubber as it contains the well pressure below. When there is no pipe in the preventer, continued upward movement of the piston forces the element to seal across the open bore (lower right). At complete shutoff, the steel segments provide ample support for the top portion of the rubber. This prevents the rubber from flowing or extruding excessively when confining high well pressure. STRIPPING OPERATIONS Stripping operations are undoubtedly the most severe application for any preventer because of the wear the sealing element is exposed to as the drill string is moved through the preventer under pressure. To prolong sealing element life, it is important to use proper operating procedures when stripping. The recommended procedures are: 1. Close the preventer with 1,500 psi closing pressure. 2. Just prior to commencing stripping operations, reduce closing pressure to a value sufficient to allow a slight leak. 3. If conditions allow, stripping should be done with a slight leak to provide lubrication and prevent excessive temperature buildup in the element. As the sealing element wears, the, closing pressure will need to be incrementally increased to prevent excessive leakage.

V4 Rev March 2002

6 - 55


Figure 6.2.15 6 - 56

V4 Rev March 2002


6.3 DIVERTERS Figure 6.3.1 Typical Diverter System Installed on a Floating Rig DIVERTER ELEMENT

DIVERTER INSERT LOCK

PRESSURE

RELAX

UNLOCK

ADJUST

CLOSED

CLOSED

OPEN

OPEN

STARBOARD VENT

PORT VENT

RETURNS TO SHAKER PRESSURE BELOW DIVERTER BAG

CLOSED

OPEN

UPPER "WORKING" PACKING ELEMENT

SLIP JOINT UPPER ELEMENT

RIG AIR

BLEED ADJUST

LOWER PACKING ELEMENT CLOSED WHEN DIVERTER IS OPERATED

SLIP JOINT UPPER ELEMENT PRESSURIZE

RELAX ADJUST

V4 Rev March 2002

SLIP JOINT ANNULUS PRESSURE

6 - 57


Typical Operating Pressures The diverter packer regulator will provide a maximum pressure of 1200 psi on the packer. For normal pressure use 750 psi. The manifold pressure regulator provides a maximum pressure of 1650 psi. For insert packer lock down dogs. Diverter lock down dogs etc. For normal operation do not exceed 1250 psi. Recommended pressure settings generally are: Hydraulic supply pressure Manifold pressure Diverter packer pressure

6 - 58

3000 psi 1250 psi 750 psi

V4 Rev March 2002


Figure 6.3.2 Hydril FSP 28-2000 Diverter/BOP System Hydraulic Schematic HOSE BUNDLE

LATCH UNLATCH

HANDLING/TEST TOOL

REGULATED HYDRAULIC SUPPLY

PUSH AND HOLD TO UNLATCH

UNLATCH PORT STBD

LATCH BELL NIPPLE LATCH

SELECTOR

REGULATED HYDRAULIC SUPPLY

PORT

OPEN CLOSE DIVERTER/BOP 5 GALLON ACCUMULATOR CERAMIC LINED AUTOMATIC OPENING TO DIVERTER LINES AS BAG CLOSES.

V4 Rev March 2002

6 - 59


Figure 6.3.3 Example diverter with annular packing element

6 - 60

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Figure 6.3.4 Example diverter with insert - type packer

V4 Rev March 2002

6 - 61


Figure 6.3.5 Example diverter with rotating stripper

6 - 62

V4 Rev March 2002


Figure 6.3.6 Example diverter systems - Integral sequencing

NOTE: When the diverter closes, the piston moves upward opening the flow path to the vent line while closing the flow path to the flow line.

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6 - 63


If an Annular Sequencing Device which requires lockdown of an insert packer is in use, the lockdown function should be included in the automatic sequencing. Figure 6.3.3 DIVERTER OPEN VALVE OPERATING PRESSURE

OPEN

VENT VALVE ACTUATOR DIVERTER CLOSE

CLOSE

OPEN

FLOWLINE VALVE ACTUATOR

CLOSE

DIVERTED ANNULAR SEALING DEVICE OPERATING PRESSURE CLOSE ANNULAR SEALING DEVICE OPEN

6 - 64

V4 Rev March 2002


Figure 6.3.4 DERRICK FLOOR BELL NIPPLE FLOW LINE INSERT TYPE PACKER HYDRAULIC VALVE OPERATOR BLEED-OFF LINE VALVE

HEAVE COMPENSATOR LINE INNER BARREL OF TELESCOPING JOINT SEA LEVEL

OUTER BARREL OF TELESCOPING JOINT

RISER COUPLING

FLEXIBLE JOINT GUIDE FRAME HYDRAULIC LATCH PERMANENT GUIDE BASE TEMPORARY GUIDE BASE

When drilling surface hole from a template the cuttings are returned to surface for disposal to avoid spool build up on the template. V4 Rev March 2002

6 - 65


Figure 6.3.5

21 in HST RISER COUPLING PIN MUD BOOST LINE CONNECTION 21 1/4 in – 2000 MSP ANNU-FLEX

FLEX JOINT

ANNULAR BOP

21in HYDRAULIC CONNECTOR 21 1/4 in – 2000 SHEAR RAM OUTLET NOZZLE(S)

21 1/4 in – 2000 FSS SPOOL

BLIND FLANGE

C K VALVE

30 in LATCH

Sub-sea diverting stack (template operations). 6 - 66

V4 Rev March 2002


Figure 6.3.6 (SURFACE DIVERTER)

V4 Rev March 2002

6 - 67


Figure 6.3.7 (MSP DIVERTER/BOP)

6 - 68

V4 Rev March 2002

V4 Rev March 2002

6"Ø RISER DIVERTER OVERBOARD LINE

12"Ø

6"Ø

FROM DRILLING CHOKE MANIFOLD

12"Ø BELL NIPPLE DIVERTER OVERBOARD LINE

MUD GAS SEPERRTOR

VENT

6"Ø

3"Ø

6"Ø

3"Ø

Riser Diverter

Riser GPLG

6" DRAPE HOSE

Riser GPLG

Riser GPLG

Upper Flex Joint

Bell Nipple Diverter

QUICK CONNECT COUPLING

CLOSE CONTROL LINE

OPEN CONTROL LINE

RISER CHOKE LINE

6"Ø

3"CHOKE

RISER DIVERTER MANIFOLD (NEAR DRILLING MANIFOLD)

PILOT CONTROL LINE TO DRILLING CONSOLE

RIG FLOOR

MUD PUMP

OUTER BARREL

16"Ø

CHOKE DRAPE HOSE

KILL DRAPE HOSE

RISER DIVERTER JOINT

RISER BOOST LINE

TELESCOPIC JOINT

INNER BARREL

MOON POOL

VENT

REGULATED HYDRUALIC SUPPLY

ACCUMULATOR BANK

TO SHALE SHAKER


Figure 6.3.8

6 - 69


Figure 6.3.9 HYDRIL ANNULAR PREVENTER - TYPE “MSP” - 2000 PSI

Operating Features:

6 - 70

1.

Will close on open hole and hold 2000 psi (but not recommended).

2.

Primary usage is in diverter systems.

3.

Automatically returns to the open position when closing is released.

4.

Sealing assistance is gained from the well pressure.

5.

Greater stripping capability of the packing unit since (fatigue) wear occurs on the outside of the packing unit. V4 Rev March 2002


ROTATING HEADS When used, rotating heads are installed above the BOP stack. They provide a seal on the kelly or drillpipe. A drive unit, attached to the kelly, locates in a bearing assembly above the stripper rubber. Some applications for rotating heads are: •

Drilling with air or gas, to divert the returns through a "Blooey line".

•

To permit drilling with underbalanced mud, by maintaining a back pressure on the wellbore.

•

As a diverter for surface hole.

•

To keep gas away from the rotary table. This is especially important where Hydrogen Sulphide can be expected.

Realistic working pressures for rotating heads are 500 to 700 psi. It is recommended that they are not installed for routine gas cap drilling (unless sour gas is expected) since their use precludes observation from the rig floor of annulus fluid level. Figure 6.3.10

KELLY BUSHING

SWING-BOLT CLAMP ASSEMBLY DRIVE BUSHING ASSEMBLY SHOCK PAD

BOWL

DRIVE RING AND BEARING ASSEMBLY

STRIPPER RUBBER

OUTLET FLANGE INLET FLANGE

V4 Rev March 2002

6 - 71


6.4 GASKETS, SEALS AND WELLHEADS API Type 'R' Ring Joint Gasket The type ‘R’ ring joint gasket is not energised by internal pressure. Sealing takes place along small bands of contact between the grooves and the gasket, on both the OD and ID of the gasket. The gasket may be either octagonal or oval in cross section. The type ‘R’ design does not allow face-to-face contact between the hubs or flanges, so external loads are transmitted through the sealing surfaces of the ring. Vibration and external loads may cause the small bands of contact between the ring and the ring grooves to deform the plastic, so that the joint may develop a leak unless the flange bolting is periodically tightened. Standard procedure with type ‘R’ joints in the BOP stack is to tighten the flange bolting weekly. Figure 6.4.1

Figure 6..4.2 CL

CL

ENERGISED

6 - 72

V4 Rev March 2002


Figure 6.4.3

V4 Rev March 2002

6 - 73


API Type 'RX' Pressure-Energised Ring Joint Gasket The ‘RX’ pressure-energised ring joint gasket was developed by Cameron Iron Works and adopted by API. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The ‘RX’ design does not allow face-to-face contact between the hubs or flanges. However, the gasket has large load-bearing surfaces on the inside diameter, to transmit external loads without plastic deformation of the sealing surfaces of the gasket. It is recommended that a new gasket be used each time the joint is made up. Figure 6.4.4

CL

Figure 6.4.5 CL

ENERGISED

6 - 74

V4 Rev March 2002


API Type 'BX' Pressure-Energised Ring Joint Gasket Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. Although the intent of the ‘BX’ design was face-to-face contact between the hubs and flanges, the groove and gasket tolerances which are adopted are such that, if the ring dimension is on the high side of the tolerance range and the groove dimension is on the low side of the tolerance range, face-to-face contact may be very difficult to achieve. Without face-to-face contact, vibration and external loads can cause plastic deformation of the ring, eventually resulting in leaks. Both flanged and clamp hub ‘BX’ joints are equally prone to this difficulty. The ‘BX’ gasket frequently is manufactured with axial holes to ensure pressure balance, since both the ID and the OD of the gasket may contact the grooves. In practice, the face-to-face contact between hubs or flanges is seldom achieved. Figure 6.4.6

Figure 6.4.7 CL

Figure 6.4.8 CL

CL

ENERGISED

V4 Rev March 2002

6 - 75


API Face-to-Face Type ‘RX’ Pressure-Energised Ring Joint Gasket The face-to-face ‘RX’ pressure-energised ring joint gasket was adopted by API as the standard joint for clamp hubs. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. Face-to-face contact between the hubs is ensured by an increased groove width, but this leaves the gasket unsupported on it’s ID. Without support from the ID of the grooves, the gasket may not remain perfectly round as the joint is tightened. If the gasket buckles or develops flats, the joint may leak. This type of gasket has not been accepted by the industry and is seldom used. Figure 6.4.9

Figure 6.4.10 CL

C L

ENERGISED

6 - 76

V4 Rev March 2002


‘CIW’ Type ‘RX’ Pressure-Energised Ring Joint Groove CIW modified the API face-to-face type ‘RX’ pressure-energised ring joint grooves to prevent any possible leaking caused by the buckling of the gasket in the API groove. The same API face-to-face type ‘RX’ pressure energised ring joint gaskets are used with these modified grooves. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The gasket ID will also contact the grooves when it is made up. This constraint of the gasket prevents any possible leaking caused by the buckling of the gasket. Hub face-to-face contact is maintained within certain tolerances. The maximum theoretical stand-off from the stack-up of the tolerances of the gasket and the groove is 0.022 inches. Face-to-face contact cannot be assured with this ring/groove combination. This ring is seldom found in use. The ‘CX’ ring accomplishes the intent of the ‘RX’ faceto-face design. Figure 6.4.13

Figure 6.4.14 CL

V4 Rev March 2002

C L

6 - 77


Type 'AX' and 'VX' Pressure-Energised Ring Joint Gasket The ‘AX’ pressure-energised ring joint gasket was developed by Cameron Iron Works. The ‘VX’ ring was developed by Vetco. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The ID of the gasket is smooth and is almost flush with the hub bore. Sealing occurs at a diameter which is only slightly greater than the diameter of the hub bore, so the axial pressure load on the connector is held to an absolute minimum. The belt at the centre of the gasket keeps it from buckling or cocking as the joint is being made up. The OD of the gasket is grooved. This allows the use of retractable pins or dogs to positively retain the gasket in the base of the wellhead or riser connector when the hubs are separated. The gasket design allows face-to-face contact between the hubs to be achieved with minimal clamping force. External loads are transmitted entirely through the hub faces and cannot damage the gasket. Figure 6.4.13

Figure 6.4.14 CL

CL

ENERGISED

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V4 Rev March 2002


‘CIW’ Type ‘CX’ Pressure-Energised Ring Joint Gasket The ‘CX’ pressure-energised ring joint gasket was developed by Cameron Iron Works. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The gasket is patterned after the ‘AX’ and ‘VX’ gasket, but is recessed, rather than being flush with the well bore, for protection against keyseating. The gasket seals on approximately the same diameter as do the ‘RX’ and ‘BX’ gaskets. The belt at the centre of the gasket keeps it from buckling or cocking as the joint is being made up. Since the ‘CX’ gasket is protected from keyseating, it is suitable for use through the BOP and riser system, except at the base of the wellhead and riser connectors. The gasket design allows face-to-face contact between the clamp hubs or flanges to be achieved with minimal clamping force. External loads are transmitted entirely through the hub faces and cannot damage the gasket. Figure 6.4.15

Figure 6.4.16 C L

V4 Rev March 2002

CL

6 - 79


Application of Type 'AX', 'VX' and 'CX' Pressure-Energised Ring Joint Gaskets The ‘AX’, ‘VX’ and ‘CX’ face-to-face pressure-energised ring gaskets allow face-toface contact between the hubs to be achieved with minimal clamping force. The ‘AX’ and ‘VX’ gasket is used at the base of the wellhead and riser connector when the hubs are separated. The ‘AX’/’VX’ design ensures that axial pressure loading on the connector is held to an absolute minimum. The ‘AX’ gasket also is suitable for side outlets on the BOP stack, since these outlets are not subject to keyseating. The ‘CX’ gasket is recessed for protection against keyseating. The ‘CX’ gasket is suitable for use throughout the BOP and riser system, except at the base of the wellhead and riser connector. Figure 6.4.17 HYDRIL DRILLING SPOOL DATA

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V4 Rev March 2002


Figure 6.4.18

V4 Rev March 2002

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Figure 6.4.19

6 - 82

V4 Rev March 2002

V4 Rev March 2002

API Type 6B with Type R Flat Bottom Groove or API Type 6BX w/Type BX Groove

API Type 6BX with Type BX Groove

5000 psi wp Installations

10,000 psi wp Installations

**

API Type BX

API Type RX or API Type BX wp Type 6BX Flange

API Type RX

APPROVED * RING GASKETS

ASTM Grade B-7

ASTM Grade B-7

ASTM Grade B-7

MAXIMUM BOLT ** STRENGTH

-

Type 316 stainless steel preferred but Type 304 stainless steel acceptable except for high risk H2S wells.

Low Carbon Steel

ASTM Grad 2-H

ASME Grade 2-H

ASTM Grade 2H

MINIMUM NUT STRENGTH

In some H2S applications, ASTM A-193 Gr B/M with a maximum Rockwell hardness of 22 may be acceptable. If used, flanges should be derated per Table 1.4B of API 6A.

Sour Oil or Gas -

Sweet Oil

Acceptable material for flange ring gaskets as per API Spec 6A, "Wellhead Equipment".

API Type 6B with Type R Flat Bottom Groove

2000 psi wp and 3000 psi wp Installations

*

APPROVED FLANGES

RATING OF BOP STACK

All blowout preventers, drilling spools, adapter flanges will be furnished with the specific API ring joint flange equipment listed below:


Figure 6.4.20 SPECIFICATIONS FOR BOP FLANGES, RING GASKETS, FLANGE BOLTS AND NUTS

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6.5 MANIFOLDS, VALVES, SEPARATORS AND FLOW GAIN SENSORS 1. MUD CONTROL AND MONITORING EQUIPMENT Correct installation and operation of this equipment is fundamental to effective primary and secondary well control. The following are the most important aspects: a) Pit Volume Measurement A pit volume totalising (PVT) should be provided. A calibrated read-out and audio alarm should be installed at the Driller’s station. The following measurement devices are required for all tanks: •

A float for the PVT system, to isolate other floats when the trip tank is in use.

•

An internal calibrated ladder-type scale.

•

A remote ladder-type scale, visible from the Driller’s station for the trip tank.

•

A small wireline can be used to connect a float in the tank to the scale on the rig floor.

b) Flow line Measurement A device should be provided for measurement of flow line and mud return rate. This (Flo Show) device should have a read-out and alarm at the Driller’s station. c) Trip Tank Trip tanks are used to fill the hole on trips, measure mud or water into the annulus when circulation has been lost, monitor the hole when tripping, logging or other similar type operations. There are two basic types of trip tanks - gravity feed and pump. The pump type system is better because it provides for safer and more expedient trip operation. The trip tank would be isolated from the surface mud system to prevent inadvertent loss or gain of mud from the trip tank due to valves being left open. In the past, many blowouts occurred due to swabbing or not keeping the hole filled while tripping the drill string out of the hole. To provide exact fluid measurements for pipe displacement, trip tanks were developed to accurately measure within ± 1.0 barrel the influx or efflux of fluid from the wellbore. As the drill string is pulled from the hole, the mud level will drop due to the volume of metal being removed. If mud is not added to the hole as pipe is pulled, it is possible to reduce hydrostatic pressure to less than formation pressure. When this happens, a kick will occur. Swabbing can occur when pipe is pulled too fast and friction between the pipe and the mud column causes a reduction in hydrostatic pressure to a valve less than formation pressure. 6 - 84

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Figure 6.5.1 MFC3 CONTROL CONSOLE

MFS 3 - Series RETURN MUD FLOW SYSTEM 40 50 60 30 20

70 80

10

%

0

MFT2 MUD FLOW SENSOR

LO ADJUST

RETURN MUD FLOW

90 100

LO HI FLOW FLOW

MUD FLOO

SMOOTHING LO

ON

MED

HI

RECORDER 115 VAC

RETURN WARNING

HI ADJUST

2 AMP

RETURN FLOW HI-LO WARNING

FLOW SENSOR

LINE

H1240 WARNING SYSTEM WARNING LIGHTS (Optional)

115 VAC

REMOTE INDICCTOR

FROM MVT4 RETURN MUD FLOW SYSTEM (Optional)

MFR2 or MFRE2 RECORDER (Optional)

HORN

Figure 6.5.2 MFTX2 FLOW SENSOR ASSEMBLY

MVR2 ELECTRONIC RECORDER (Optional)

MFCX RETURN MUD FLOW AND PUMP STROKE SENSOR CONSOLE 40 50 60 30 20 10

70 80 90

0

100

H1268 WARNING SYSTEM HORN

H1267 WARNING SYSTEM CONTROL BOX

H1234A PUMP STROKE SENSOR

MFSX2 MUD FLOW FILL SYSTEM

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To prevent loss of hydrostatic pressure it is necessary to fill the hole on a regular schedule, or continuously, using a trip tank to keep the track of the fluid volume required. The metal volume of the pipe being pulled can be calculated, but mud additions necessary to replace hole seepage losses due to filtration effects can only be predicted by comparison with the mud volumes required to keep the hole properly filled on previous trips. For this reason, it is import that a record of mud volume required, versus number of stands pulled be maintained on the rig in a trip book for every trip made. Typical Trip Tank Hook-up - On A Floating Rig As illustrated in Figure 6.5.3, a centrifugal pump takes suction from the trip tank and fills the hole through a line into the bell nipple. The pump runs constantly while the drill string is pulled from the hole. The hole stays full as each stand of pipe is pulled and excess mud returns to the trip tank through an outlet on the main flow line. A valve must be installed in the flow line downstream of this outlet to block all flow to the shale shakers while making a trip. A closed circulation system can be monitored by a float system and a digital read-out in 1-barrel increments on the Driller’s console. Mud Gas Separator The separator is installed downstream of the choke manifold to separate gas from the drilling fluid. This provides a means of safely venting the gas and returning usable liquid mud to the active system. There are two types of mud gas separators: Atmospheric and Pressurised.

6 - 86

•

The atmospheric type separator is standard equipment on nearly all rigs and is referred to in the field as a ‘gas buster’ or ‘poorboy' separator. The main advantage of this type of separator is its operational simplicity which does not require control valves on either the gas or mud discharge lines.

•

A pressurised mud gas separator is designed to operate with moderate back pressure, generally 50 psi or less. Pressurised separators are utilised to overcome line pressure losses when an excessive length of vent line is required to safely flare and burn the hazardous gas an extended distance from the rig. The pressurised separator is considered special rig equipment and may not be provided by the contractor. This type of separator is installed on rigs drilling in high risk H2S areas and for drilling underbalanced in areas where high pressure, low volume gas continually feeds into the circulating fluid.

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During well control operations, the main purpose of a mud gas separator is to vent the gas and save the drilling fluid. This is important not only for economic reasons, but also to minimise the risk of circulating out a gas kick without having to shut down to mix additional mud volume. In some situations the amount of mud lost can be critical when surface volume is marginal and on-site mud supplies are limited. When a gas kick is properly shut in and circulated out, the mud gas separator should be capable of saving most of the mud. There are a number of design features which affect the volume of gas and fluid that the separator can safely handle. For production operations, gas oil separators can be sized and internally designed to efficiently separate gas from the fluid. This is possible because the fluid and gas characteristics are known and design flow rates can be readily established. It is apparent that ‘gas busters’ for drilling rigs cannot be designed on the same basis since the properties of circulated fluids from gas kicks are unpredictable and a wide range of mixing conditions occur downhole. In addition, mud rheological properties vary widely and have a strong effect on gas environment. For both practical and cost reasons, rig mud gas separators are not designed for maximum possible gas release rates which might be needed; however, they should handle most kicks when recommended shut-in procedures and well control practices are followed. When gas low rates exceed the separator capacity, the flow must be bypassed around the separator directly to the flare line. This will prevent the hazardous situation of blowing the liquid from the bottom of the separator and discharging gas into the mud system. Figure 6.5.4 illustrates the basic design features for atmospheric mud gas separators. Since most drilling rigs have their own separator designs, the Drilling Supervisor must analyse and compare the contractor’s equipment with the recommended design to ensure the essential requirements are met. The atmospheric type separator operates on the gravity or hydrostatic pressure principle. The essential design features are: •

Height and diameter of separator.

•

Internal baffle arrangement to assist in additional gas break-out.

•

Diameter and length of gas outlet.

•

A target plate to minimise erosion where inlet mud gas mixture contacts the internal wall of the separator, which provides a method of inspecting plate wear.

•

A U-tube arrangement properly sized to maintain a fluid head in the separator.

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Figure 6.5.3 REMOTE CONTROL VALVE

TRIP TANK LEVEL INDICATOR

RIG FLOOR

OVERBOARD

ROTARY TABLE

DIVERTER RETURNS TO SHAKERS

FLOWLINE

HOLE FILL UP LINE

TELESCOPIC JOINT FROM MISSION PUMPS RISER CHECK VALVE

DRAIN

TRIP TANK PUMP

Figure 6.5.4 An Example Mud Gas Separator GAS OUTLET 8" ID MINIMUM GAS BACK PRESSURE REGISTERED AT THIS GAUGE

STEEL TARGET PLATE

(Typically 0 to 20 psi)

APPROX 1/2 OF HEIGHT

10' MINIMUM HEIGHT

INLET

INSPECTION COVER

30" OD

SECTION A-A TANGENTIAL INLET

A INSPECTION COVER

A

4" ID INLET-TANGENTIAL TO SHELL FROM CHOKE MANIFOLD

BRACE

HALF CIRCLE BAFFLES ARRANGED IN A 'SPIRAL' CORFIGURATION

10' APPROX

TO SHAKER HEADER TANK

MAXIMUM HEAD AVAILABLE DEVELOPED BY THIS HEIGHT OF FLUID eg 10 foot HEAD AT 1.5 SG GIVES 6.5 psi MAXIMUM CAPACITY

8" NOMINAL 'U' TUBE 4" CLEAN-OUT PLUG

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2" DRAIN OR FLUSH LINE

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The height and diameter of an atmospheric separator are critical dimensions which affect the volume of gas and fluid the separator can efficiently handle. As the mud and gas mixture enters the separator, the operating pressure is atmospheric plus pressure due to friction in the gas vent line. The vertical distance from the inlet to the static fluid level allows time for additional gas break-out and provides an allowance for the fluid to rise somewhat during operation to overcome friction loss in the mud outlet lines. As shown in Figure 6.5.4, the gas-fluid inlet should be located approximately at the midpoint of the vertical height. This provides the top half for a gas chamber and the bottom half for gas separation and fluid retention. The 30 in. diameter and 16 ft minimum vessel height requirements have proven adequate to handle the majority of gas kicks. The separator inlet should have at least the same ID as the largest line from the choke manifold, which is usually 4 in. Some separators use tangential inlet, which creates a small centrifugal effect on the gas-fluid mixture and causes faster gas break-out. The baffle system causes the mud to flow in thin sheets which assists the separation process. There are numerous arrangements and shapes of baffles used. It is important that each plate be securely welded to the body of the separator with angle braces. A 8 in. minimum ID gas outlet is usually recommended to allow a large volume of low pressure gas to be released from the separator with minimum restriction. Care should be taken to ensure minimum back pressure in the vent line. On most offshore rigs, the vent line is extended straight up and supported to a derrick leg. The ideal line would be restricted to 30 ft in length and the top of the line should be bent outward about 30 degrees to direct gas flow away from the rig floor. If it is intended that the gas be flared, flame arresters should be installed at the discharge end of the vent line. As stated previously, when the gas pressure in the separator exceeds the hydrostatic head of the mud in the U-tube, the fluid seal in the bottom is lost and gas starts flowing into the mud system. The mud outlet downstream of the U-tube should be designed to maintain a minimum vessel fluid level of approximately 3 1/2 ft in a 16 ft high separator. Assuming a 9.8 ppg mud and total U-tube height of 10 ft, the fluid seal would have a hydrostatic pressure equal to 5.096 psi. This points out the importance for providing a large diameter gas vent line with the fewest possible turns to minimise line frictional losses. The mud outlet line must be designed to handle viscous, contaminated mud returns. As shown in Figure 6.5.4 an 8 in. line is recommended to minimise frictional losses. This line usually discharges into the mud ditch in order that good mud can be directed over the shakers and untreatable mud routed to the waste pit.

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Degassers If a fluid's viscosity does not allow gas to break out completely, a degasser may also be used. A degasser is not designed to handle large volumes of gas, because the volume of gas actually entrained in the fluid is small. Degassers separate entrained gas from fluid using a vacuum chamber, a pressurised chamber, a centrifugal spray, or a combination. The most commonly used degassers are vacuum tanks and centrifugal pump sprayers, but many others are available. Properly maintaining degassers is not difficult. Primarily, it is a matter of correctly lubricating any pumps used in the system. In degassers that employ a float arm, joints must be kept lubricated. When a vacuum pump is used, the water knockout ahead of the compressor must be emptied daily. In general, vacuum degassers are very effective with heavy, viscous muds from which it is difficult to extract gas with a separator alone. In any degassing operation, residence time and extraction energy requirements are increased as mud viscosity and gel strength increases. Figure 6.5.5 FLARE LINE

DISCHARGE

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SUCTION

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Choke Manifolds The choke manifold is an arrangement of valves, fittings, lines and chokes which provide several flow routes to control the flow of mud, gas and oil from the annulus during a kick. Figure 6.5.6 Adjustable choke To pit and/or mud/gas separators

P

2" Nominal 2"

Blowout Preventer Stack Outlet

Remotely Operated Valve

2" Bleed line To pit

P

3" Nominal Sequence Optional

4" Nominal 2"

2" To mud/gas separator and/or pit

P

2" Nominal Remotely operated or adjustable choke

Typical Choke Manifold for 5,000 psi Working Pressure Service-Surface Installation

Figure 6.5.7 Remotely operated choke To mud/gas separators and/or pit

P

2" Nominal 2"

Adjustable Choke 2" To pit 2" Nominal

Blowout Preventer Stack Outlet

CHOKE LINE

2" Bleed line

P

To pit 3" Nominal Sequence Optional

4" Nominal 2"

Remotely Operated Valve

2"

P

To mud/gas separator and/or pit

2" Nominal Remotely operated choke

Typical Choke Manifold for 10,000 psi and 15,000 psi Working Pressure Service-Surface Installation

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Figure 6.5.8 BYPASS TO POORBOY DEGASSER TO POORBOY OR TRIP TANK DEGASSER

TO MUD PITS

2 4

2 3

1 BOP STACK

1

PRIMARY CHOKE LINE

1

1

1

1

2 RESERVE PIT (DERRICK FLARE OFFSHORE RIGS)

CHOKE BYPASS LINE KILL OR SECONDARY CHOKE LINE

1 1

2 3

BUFFER CHAMBER

FROM KILL PUMP

TO GAUGE

2 4 MANIFOLD CHOKE LINE

FROM DST CHOKE MANIFOLD DST LINE

1. 10,000 psi gate valves. 2. 5,000 psi gate valves. 3. Remote controlled chokes. 4. Manually adjusted chokes.

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2

BURNING LINE (PRODUCTION GAS SEPARATOR OFFSHORE RIGS)

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SPECIFICATION 1 13/16" THRU 2 9/16", 10,000 PSI Figure 6.5.9

Figure 6.4.10 E

C

A

C

B

10,000 lb Working Pressure (Inches) Size

WP

A

B

C

D

E

Wt

No of Turns to Open

1 13/16"

10,000

1 13/16

18 1/4

5 11/16

18 5/8

8

206

12 1/2

2 1/16"

10,000

2 1/16

20 1/2

5 11/16

18 5/8

9 3/4

218

13 1/2

2 9/16"

10,000

2 9/16

22 1/4

6 7/8

19 1/2

9 3/4

292

16

Flange specifications conform to API standard 6A

National Gate Valves are available with flanged ends in standard API bore sizes and working pressures. Special trims are available for sour gas and oil service on request. National Gate Valves are also readily available to accept most pneumatic or hydraulic operators. National Gate Valves meet the applicable standards set forth by the American Petroleum Institute. When ordering, be sure to specify quantity, size, working pressure, end connection, body and trim materials, and service conditions (such as temperature, pressure, and composition of flow material). V4 Rev March 2002

6 - 93


. Figure 6.4.11 - Components 113/16" thru 21/16" 15,000 psi Hex Nut

Handwheel

Bearing Grease Fitting

Stem

Bonnet Cap Grease Seal

Set Screw

Flat Split Ring

Clevis Nut

Hub Seal

O-Ring

Stem Bearing

Clevis Pin

Shoulder Split Ring Packing Gland

Gate

Hex Nut Stem Packing Packing Header Ring Plastic Packing

Seat Assembll

Plastic Packing Injection Fitting

Stud Bolt

Bonnet

Body

Grease Fitting

6 - 94

Bonnet Gasket Grease Fitting

V4 Rev March 2002


Figure 6.5.12 - Type ‘HCR‘ pressure operated gate valve

The type ‘HCR‘ pressure operated gate valves is a flow line valve requiring relatively low operating pressures. This is a single ram, hydraulic gate valve packed with elements similar to the old ‘QRC‘ ram assembly. The closing ratio of well pressure to hydraulic operating pressure is approximately 8 to 1. Available sizes are 4-inch 3000 to 5000 psi working pressure, and 6-inch 3000 and 5000 psi working pressure with standard API flanges.

V4 Rev March 2002

6 - 95


Figure 6.5.13

Figure 6.5.14

Cameron type “F“ Gate Valve The Cameron type “F“ gate valve is a commonly used valve on BOP system lines. The valve is conduit type with no pockets for solids to deposit and hardened rotating seats which distribute wear. Gates and seats may be replaced without disconnecting the valves. These valves may be equipped with either hydraulic or pneumatic operators. Control pressure is lower, especially at high operating pressures. Sizes from 1-13/16 to 6-6/8 inch are available in ratings of 2,000 to 10,000 working pressure. Fail-safe type “F“ valves are opened and held open by control pressure in the operating cylinder. Line pressure tends to close the valve because the gate and stem move outward in closing. Closing force is supplied by valve body pressure acting on the stem area, plus the action of a coiled spring. Since operating pressure is low so that closing ratio is not a problem, “fail-safe“ models close automatically upon loss of pressure and are ideally suited for subsea use. 6 - 96

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Fail Safe Valves High pressure choke and kill lines run from the stack to the choke manifold on the rig floor. To shut these lines off when not required, each is equipped with two fail safe valves. These can be opened hydraulically from the surface but when the opening pressure is released spring action automatically forces the gate closed. The valves are always rated at the same pressure as the stack and choke and kill lines. Due to space limitations the first valve out from the stack (the inner valve) is a 90 degree type with a target to avoid sand cutting. The outer valve is straight through and must be able to hold pressure from on top as well as below when the choke and kill lines are tested. In the Cameron type AF fail safe valve (fig 6.5.15) flow line pressure acting against the lower end of the balancing stem assists in closing the valve. A port in the operator housing allows the hydrostatic pressure due to water depth to balance the hydrostatic head of the operating fluid. A resilient sleeve transmits the sea water pressure to an oil chamber on the spring side of the operating piston. Without this feature the hydrostatic head of the operating fluid acting on top of the piston would tend to open the valve itself, especially in deep water. Liquid lock between the two valves in each line is eliminated by porting the fluid exhausted from the pressure chamber when opening the valve, away from the neighbouring valve.

V4 Rev March 2002

6 - 97


Figure 6.5.15

Woodruff key Locking ring Sea water hydrostatic pressure

Operator fluid inlet Retainer ring Piston Set screw "O" Ring

Spring cartridge assembly Sea water hydrostatic pressure equalizing port

Resilient sleeve Sleeve

Clamp Ring "J" Packing Vent "O" ring

Ring

"J" Packing Junk ring Retainer ring Pin

Pipe plug Anti-extrusion ring Bonnet stud Bonnet nut Bonnet

Pipe plug Bonnet gasket

Gate and seat assembly Body

Pin Adaptor stem Balancing stem "O" ring "J" packing "O" ring "O" ring "J" packing Nut "O" ring Gland Pipe plug

CAMERON TYPE AF FAIL SAFE VALVE

6 - 98

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Figure 6.5.16

V4 Rev March 2002

6 - 99


Figure 6.5.17

6 - 100

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K Choke Beans and Wrenches •

Flared Orifice entrance reduces erosion on the entrance surface.

•

Accuracy levels are maintained over extended periods of use.

•

Choke beans save time and money because replacement intervals are extended.

Cameron K choke beans come in two styles, positive and combination. The positive bean has a fixed orifice diameter. The combination bean has a fixed diameter and a throttling taper at the entry. The combination bean is used with an adjustable choke needle to make incremental changes to orifice sizes smaller than the fixed orifice. The part numbers of the positive and combination beans are determined by desired orifice size. K1 positive bean orifice sizes range from 4/64" to 64/64"/ Part numbers for K1 positive beans are available on request. K2 positive bean orifice sizes range from 4/64" to 128/64". The part number for K2 positive bean is 626397-( )-( ). The dash numbers indicate desired orifice size; for example, 626397-01-10 is a 110/64" diameter orifice. K3 positive bean orifice sizes range from 4/64" to 192/64". Part numbers for K3 positive beans are available on request. K1 combination bean sizes range from 6/64" to 64/64". K2 combination bean sizes range form 6/64" to 128/64". The part number for the K2 combination bean is 626396-( )-( ). K3 combination bean sizes range from 6/64" to 192/64". Part numbers for the K1 and K3 combination beans are available upon request. The part number of the K2 bean wrench is 626266-01. The part numbers of the K1 and K3 bean wrenches are available on request.

V4 Rev March 2002

6 - 101


6.6 INSIDE BOP'S Drill Pipe Float Valves The drill pipe float valve and the flapper type of back pressure valve, serve essentially the same purpose, but differ in design. These valves provide instantaneous shut-off against high or low back pressure and allow full fluid flow through the drill string. Another advantage is that it prevents cuttings from entering the drill string, thus reducing the likelihood of pulling a wet string. Abnormal pressures and anticipated subnormal pressure zones should be the deciding factor regarding what type of valve to run or the possibility of not running any valve at all. Expectations of abnormal pressures have shown the vented type of flapper valve to be the most popular because of the ease involved in recording shut-in drill pipe pressures. The disadvantages are that the pipe must be filled while tripping in, and reverse circulation is not possible. Figure 6.6.1

6 - 102

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Figure 6.6.2 - Kelly Cock

Figure 6.6.3 - Gray Valve

RELEASE TOOL VALUE RELEASE ROD

Body

Upper Seat

Crank VALVE SEAT

Ball

Lower Seat

VALVE SPRING

Figure 6.6.4 Installing a Checkguard improves well control significantly. It serves as a check valve to prevent upward flow through the drill string while permitting downward mud pumping or flow from injectors. While stripping drill pipe into the hole, Checkguard control upward pressure in the annulus and in the drill pipe. Latching the check valve into the landing sub contains the pressure in the drill pipe. Prior to shearing drill pipe, install the check valve to protect against the release of well pressures. Installation of the check valve simplifies well control, since formation pressures cannot communicate up the drill string. While tripping, Checkguard contains upward well bore pressure in the drill pipe, allowing the top connection to be open. V4 Rev March 2002

6 - 103


Checkguard uses a spring and ball design. Fluid can be pumped through the valve from the top. But when fluid tries to flow from the bottom to the top, it is sealed by the spring-loaded ball against the seat. A large rubber packer provides sealing when fluid attempts to flow around the valve. The packer is engaged by the tapered body. The body is driven upward by pressure from below. The more pressure from below, the tighter the seal is. Installation and Retrieval Install the landing sub in the drill string while tripping into the hole. Position the landing sub in the lower end of the drill string. Install the check valve by dropping it into an open tool joint. Connect the kelly and pump the check valve into the landing sub. Use the drill pipe safety kelly guard and lower the kelly guard if excessive back flow exists. Retrieve the check valve by installing a sinker bar above the retrieving tool and using a wire line. Use normal wire line procedure. Another way is to trip the drill string and remove the check valve from the landing sub with the retrieval tool. Operating tips include ensuring the packer rubber is clean and pliable. Check for foreign substances such as paint, grease and dirt on the packer surface. Check for cracking and embrittlement of packer. Never oil rubber packer. Replace packer if condition requires. The check valve should be disassembled, cleaned and lubricated (not packer) once it is retrieved from the landing sub after downhole use. The valve should be stored in a protected area, away from sun and rain while not in use. This protects the working parts and packer.

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SECTION 7 :

INSPECTION, TESTING AND SEALING COMPONENTS Page

7A

Inspection and Testing - Surface Installations

1

7B

Inspection and Testing - Subsea Installations

12

7C

Sealing Components - Surface Installations

14

7D

Sealing Components - Subsea Installations

15

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WELL CONTROL for the Rig-Site Drilling Team SECTION 7 : INSPECTION & TESTING

SECTION 7-A INSPECTION AND TESTING - SURFACE INSTALLATIONS FIELD ACCEPTANCE INSPECTION AND TESTING 7.A.1 The field acceptance procedure should be performed each time a new or reworked blowout preventer or blowout preventer of unknown condition is placed in service. Ram Type Preventers and Drilling Spools 7.A.2 Following are recommended inspections and tests for this equipment: a.

Visually inspect the body and ring grooves (vertical, horizontal, or ram bore) for damage, wear, and pitting.

b.

Check bolting, both studs and nuts, for proper type, size, and condition. Refer to Section 8-A for bolting recommendations.

c.

Check ring joint gaskets for proper type and condition. Refer to Section 8-A for ring joint gasket recommendations.

d.

Visually inspect ram type preventers for: 1) Wear, pitting, and or damage to the bonnet or door seal area, bonnet or door seal grooves, ram bores, ram connecting rod, and ram operating rods. 2) Packer wear, cracking, and excessive hardness, Refer to Section 8-A for information on sealing components. 3) Measure ram and ram bore to check for maximum vertical clearance according to manufacturer’s specifications. This clearance is dependent on type, size, and trim of the preventers. 4) If preventer has secondary seals, inspect secondary seals and remove the plugs to expose plastic packing injection ports used for secondary sealing purposes. Remove the plastic injection screw and the check valve in this port. (Some preventers have a release packing regulating valve that will need to be removed.) Probe the plastic packing to ensure it is soft and not energising the seal. Remove and replace packing if necessary.

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7-1


e.

Hydraulically test with water using the following procedure (refer to Para. 7.A.5 for test precautions): 1) Connect closing line(s) to preventer(s). 2) Set preventer test tool on drill pipe below preventer(s) if testing preventer with pipe rams. 3) Check for closing chamber seal leaks by applying closing pressure to close the rams and check for fluid leaks by observing opening line port(s). Closing pressure should be equivalent to the manufacturer’s recommended operating pressure for the preventer’s hydraulic system. 4) Release closing pressure, remove closing line(s), and connect opening line(s). 5) Check for opening chamber seal leaks by applying opening pressure to open rams and check for fluid leaks by observing closing line port(s). Opening pressure should be equivalent to the manufacturer’s recommended operating pressure for the preventer’s hydraulic system. 6) Release opening pressure and reconnect closing line(s). 7) Check for ram packer leaks at low pressure by closing rams with 1500 psi operating pressure and apply pressure under rams to 200-300 psi with blowout preventer test tool installed (when testing preventer containing pipe rams). Hold for three minutes. Check for leaks. If ram packer leaks, refer to step 9. If ram packer does not leak, proceed to step 8. 8) Check for ram packer leaks by increasing pressure slowly to the rated working pressure of the preventer. Hold for three minutes. Check for leaks. If ram packer leaks, proceed to step 9. 9) If rams leak, check for worn packers and replace if necessary. If the preventer is equipped with an automatic locking device, check same for proper adjustment in accordance with manufacturer’s specifications. Continue testing until a successful test is obtained. 10) Test the connecting rod for adequate strength by applying opening pressure as recommended by the manufacturer with rams closed and blowout preventer rated working pressure under the rams. 11) Release opening pressure and release pressure under rams. 12) Repeat procedure (steps 1 through 9) for each set of pipe rams. 13) Test blind rams in same manner as pipe rams (step 1, steps 3 through 9) with test plug installed but test joint removed.

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Annular Blowout Preventers and Diverters 7.A.3 Following are recommended inspections and tests for this equipment: a.

Visually inspected: 1) Studded face of preventer head for pitting and damage, particularly in ring groove and stud holes. 2) Body for wear and damage. 3) Vertical bore for wear and damage from drill string and drill tools. 4) Inner sleeve for pitting and damage. Look through slots in base of inner liner for cuttings that might be trapped, thereby preventing full movement of the piston. 5) Packer for wear, cracking excessive hardness, and correct elastomer composition. Refer to Section 8-A for information on sealing components. 6) Bolting (both studs and nuts) for proper type, size, and condition. Refer to Section 8-A for bolting recommendations. 7) Ring-joint gaskets for proper type and condition. Refer to Section 8-A for ring-joint gasket recommendations.

b.

Hydraulic test using the following procedure: 1) Connect closing line to preventer. 2) Set blowout preventer test tool on drill pipe below preventer. 3) Test the seals between the closing chamber and wellbore and between the closing chamber and opening chamber by closing preventer and applying manufacturer’s recommended closing pressure. If other chambers are located between the wellbore and operating chamber, this seal should also be tested. 4)

a) If pressure holds, refer to step 13. b) If pressure does not hold and no fluid is running out of opening chamber opening, the seal between the closing chamber and the wellbore or other operating chambers is leaking. Refer to step 11. c) If fluid is coming out of the opening chamber opening, indicating the seal between the closing chamber and opening chamber is leaking, proceed to step 5.

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5) Release closing pressure. 6) Install plug in opening chamber opening, or if opening line is equipped with a valve install opening line and close valve. 7) Test seals between the closing chamber, operating chambers, and wellbore by applying manufacturer’s recommended closing pressure. Observe to see that pressure holds. 8) Release closing pressure. 9) Remove plug in opening chamber opening and install opening line or open valve in opening line. 10) Apply 1500 psi closing pressure. 11) Apply 1500 psi wellbore pressure. 12) Bleed closing pressure to 1000 psi. 13) To test the seal between the wellbore and the closing chamber. Close valve on closing line and disconnect closing line from valve on closing unit side of valve. Install pressure gauge on closing unit side of valve and open valve. If this seal is leaking, the closing line will have pressure greater than 1000 psi. Caution: If the closing line does not have a valve installed, the closing line should not be disconnected with pressure trapped in the closing chamber. 14) Release wellbore pressure. 15) Release closing pressure. 16)

a) To test the seals between the opening chamber and the closing chamber and between the opening chamber and the piston, apply manufacturer’s recommended opening pressure. If pressure holds, refer to step 21. b) If pressure does not hold and no fluid is running out of the closing chamber opening, the seal between the opening chamber and the piston is leaking. Verify this visually. Refer to step 21. c) If fluid is coming out of the closing chamber opening, indicating the seal between the opening chamber and the closing chamber is leaking, proceed to step 17.

17) Release opening pressure.

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18) Install closing line and block flow (close valve in closing line, if available). 19) Apply 1500 psi opening pressure. If pressure does not hold, seal between the opening chamber and the preventer head is leaking. Verify this visually. 20) Release opening pressure and replace necessary seals. Refer to step 22. 21) Release opening pressure, replace closing line, and replace necessary seals. 22) If closing line has a valve installed, make certain that valve is open at the end of the test. NOTE: This procedure tests all seals except the seal between the wellbore and the opening chamber. This seal should be tested in the bottom annular preventer if two annular preventers are being used or if a stack is nippled up on an annular preventer (for snubbing. etc.). It can be tested as follows: a) To rated working pressure by running a test joint and plug, closing an upper preventer, removing the opening line, and pressuring the preventer stack. b) To 1500 psi maximum, or by closing an upper preventer and the annular preventer, removing the opening line, and pressuring up between preventers. PERIODIC FIELD TESTING Blowout Preventer Operating Test 7.A.4 A preventer operating test should be performed on each round trip but not more than once per day. The test should be conducted as follows while tripping the drill pipe with the bit just inside casing: a.

Install drill pipe safety valve.

b.

Operate the choke line valves.

c.

Operate adjustable chokes. Caution: Certain chokes can be damaged if full closure is effected.

d.

Position blowout preventer equipment to check choke manifold. Open adjustable chokes and pump through each choke manifold to ensure that it is not plugged. If choke manifold contains brine, diesel or other fluid to prevent freeze-up in cold weather, some other method should be devised to ensure manifold, lines, and assembly are not plugged.

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e.

Close each preventer until all pipe rams in the stack have been operated. Caution: Do not close pipe rams on open hole. If blind rams are in the stack, operate these rams while out of the hole.

f.

Return all valves and preventers to their original position and continue normal operations. Record test results.

g.

Annular preventers need not be operated on each round trip. They should, however, be operated at an interval not to exceed seven (7) days.

Blowout Preventer Hydraulic Tests 7.A.5 The following items should be checked each time a preventer is to be hydraulically tested: a.

Verify wellhead type and rated working pressure.

b.

Check for wellhead bowl protector.

c.

Verify preventer type and rated working pressure.

d.

Verify drilling spool, spacer spool, and valve types and rated working pressures.

e.

Verify ram placement in preventers and pipe ram size.

f.

Verify drill pipe connection size and type in use.

g.

Open casing valve during test, unless pressure on the casing or hole is intended.

h.

Test pressure should not exceed the manufacturer’s rated working pressure for the body or the seals of the assembly being tested.

i.

Test pressure should not exceed the values for tensile yield, collapse and internal pressure tabulated for the appropriate drill pipe as listed in API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits*.

j.

7-6

Verify the type and pressure rating of the preventer tester to be used.

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TABLE 7-A Test Pressure Recommendations

Preventer Equipment Tested

Blowout preventer stack rated working pressure (or as specified in Notes below.)

1. Entire blowout preventer stack. 2. All choke manifold components upstream of chokes. 3. All kelly valves, drill pipe, and tubing safety valves. 4. Drilling spools, intermediate casingheads, and side outlet valves.

Rated working pressures of preventers or 3000 psi. whichever is less

1. Closing unit valves and manifold 2. All operating lines.

Casing test pressure

1. Any blind rams below drilling spool. 2. Primary casinghead and side outlet valves. 3. Casing string.

Fifty percent (50%) of rated working pressure or components

1. Choke manifold components downstream of chokes

200 - 300 psi.

1. All ram type preventers 2. Annular preventers 3. Hydraulically operated valve.

Notes: 1. Initial test pressure for the blowout preventer stack, manifold, valves, etc., should be the lesser of the rated working pressure of the preventer stack, wellhead, or upper part of the casing string. 2. Optional test - a rated working pressure test on top flange of the annular preventer. A companion test flange will be required. *Available from American Petroleum Institute. Production Department. 2535 One Main Place, Dallas TX 75202-3904.

7.A.6 An initial pressure test should be conducted on all preventer installations prior to drilling the casing plug. Conduct each component pressure test for at least three minutes. Monitor secondary seal ports and operating lines on each preventer while testing to detect internal seal leaks. 7.A.7 Subsequent pressure tests of blowout preventer equipment should be performed after setting a casing string, prior to entering a known pressure transition zone, and after a preventer ram and/or any preventer stack or choke manifold component change; but no less than once every 21 days. Equipment should be tested to at least 70 percent of the preventer rated working pressure, but limited to the lesser of the rated working pressure of the wellhead or 70 percent of the minimum internal yield pressure of the upper part of the casing string: however, in no case should these or subsequent test pressures be less than the expected surface pressure. An exception is the annular preventer which may be tested to 50 percent of its rated working pressure to minimise pack-off element wear or damage. After a preventer stack or manifold component change, hydraulically test in accordance with the provisions in Par. 7.A.6 and Table 7-A. Precautions should be taken not to expose the casing to test pressures in excess of its rated strength. A means should be provided to prevent pressure build up on the casing in the event the test tool leaks.

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Closing Unit Pump Capability Test 7.A.8 Refer to Par. 5.A.21 for closing unit pump capability test details. Accumulator Tests 7.A.9 Refer to Paras. 5.A.22 and 5.A.23 for accumulator tests details. Auxiliary Equipment Testing 7.A.10 The lower kelly valve, kelly, kelly cock, and inside blowout preventer should be tested to the same pressure as the blow out preventer stack at the same time the preventer assembly tests are made. This equipment should be tested with pressure applied from below. MAINTENANCE PROCEDURES 7.A.11 Field welding on a blowout preventer or related equipment is not recommended. 7.A.12 The service life of annular preventer packing units can be extended by: a.

Closing on pipe rather than full closure.

b.

Using closing pressures recommended by the manufacturer.

c.

Utilising the type of elastomer packing unit that best suits the drilling fluid conditions and environment expected .

d.

Proper use of a regulator or accumulator when stripping tool joints. Rapid movement of a tool joint through the preventer packing unit may cause severe damage and early failure of the packing unit.

7.A.13 If elastomer parts are to be stored for a long time period, sealed containers will help extend their useful life. Refer to Section 8-A for information on extending the life of elastomers for preventers and related equipment. 7.A.14 When a blowout preventer is taken out of service, it should be completed washed, steamed, and oiled. The rams (sealing element) should be removed and the ram bore washed inspected, and coated with a rust inhibitor. Flanged faces should be protected with wooden covers. Any burrs or galled spots should be smoothed.

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TEST PLUGS AND TEST JOINTS 7.A.15 Test Plugs. Several makes of test plugs are available for testing preventer stacks. The testing tool arrangement should provide for testing the bottom blowout preventer flange. Test plugs generally fall into two types, hanger type and cup type. a.

The hanger type test plug has a steel body with outer dimensions to fit the hanger recess of corresponding types of casinghead. An O-ring pressure seal is provided between the tester and the hanger recess (refer to Figs 7.A.1 and 7.A.2). The tester is available in various sizes depending on wellhead type and size and is equipped with tool joint connections. These plugs should be constructed with an upper bevel and/or bevelled groove (refer to Figs, 7.A.1 and 7.A.2) to facilitate the use of locking screws. The O-ring groove, if used, should be machined to permit a pressure seal from above or below the plug. Other types of seals should also be capable of holding pressure from above or below the plug. Weep holes may be drilled in the pin end of the test joint or may be installed in the test plug. These testers can be provided with a plug to test blind rams with the drill string removed. The tester can be retrieved with the drill string.

b.

The cup type test plug (refer to Figs. 7.A.3 and 7.A.4) consists of a mandrel threaded with a box on top and a pin on bottom, for a tool joint connection. A cup type pressure element holds pressure from above. Some models (refer to Fig. 7.A.1) contain a back pressure valve to bypass fluid when going in the hole. Also, a set of snap plugs (usually 4) can be provided integral to the mandrel so that the snap plugs can be broken off by dropping a bar inside the pipe, thereby allowing the annulus to be connected with the inside of the drill pipe to permit pulling the tool without swabbing the hole.

7.A.16 Test Joints. The test joint should be made of pipe of sufficient weight and grade to safely withstand tensile yield, collapse or internal pressures that will be placed on it during, testing operations Refer to API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits* for tabulated data listed by pipe size, grade, weight, and class (condition of pipe). The test joint (refer to Fig. 7.A.5), or a box and pin sub on top of a standard joint of drill pipe, should have a tapped or welded connection below the box end connection equipped with a valve, gauge, and fittings having a working pressure at least equal to the rated working pressure of the preventer stack. Weep holes may be drilled in the pin end of the test joint or may be installed in the test plug. 7.A.17 Casing Ram Test Sub. Fig. 7.A.6 illustrates a casing ram test sub. Casing rams can be tested by connecting this test sub between the test joint and the test plug so that the sub can be placed in the casing rams to be tested. A casing ram test sub can be made by welding tool joint connections on the ends of a short length of casing of desired diameter. *Available from American Petroleum Institute. Production Department. 2535 One Main Place, Dallas TX 75202-3904.

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LOCKING FLANGE MUST BE REMOVED BEFORE NEXT SECTION OF WELLHEAD IS INSTALLED

Figure 7.A.1

Figure 7.A.2

HANGER TYPE TEST PLUG HELD IN PLACE WITH LOCKING FLANGE LOCK SCREWS

HANGER TYPE TEST PLUG HELD IN PLACE WITH CASINGHEAD LOCK SCREWS

EXAMPLE OF HANGER TYPE TEST PLUGS

MANDREL SNAP PLUGS 90° SPACING

MANDREL

RETAINING NUT RETAINING PLATE PRESSURE SEAL

CUP

SIZE PLATE TAPPED FOR 1" SNAP PLUGS 90° SPACING

SUB 'O' RING

LOWER VALVE SNAP BAR RETAINING SLEEVE

Figure 7.A.3

Figure 7.A.4

EXAMPLE CUP TYPE TEST PLUGS

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V4 Rev March 2002

FIG. 7.A.5 EXAMPLE TEST JOINT

WEEP HOLE

1" OR LARGER VALVE

TOOL JOINT PIN TO MATCH TEST PLUG

WEEP HOLE

CASING SUB OF SUFFICIENT LENGTH TO TEST CASING RAMS

TOOL JOINT BOX TO MATCH TEST JOINT

FIG. 7.A.6 EXAMPLE CASING RAM TEST SUB

STEEL PLATE (WELDED TO CASING SUB AND TOOL JOINT BOX)

STEEL PLATE (WELDED TO CASING SUB AND TOOL JOINT BOX)


7 - 11


SECTION 7-B INSPECTION AND TESTING—SUBSEA INSTALLATIONS SURFACE INSPECTION AND TESTING 7.B.1 Prior to delivery to an offshore drilling unit, visually inspect the preventers, spools, high pressure connector, and kill and choke valves for condition of bodies, machined surfaces, grooves, actuating rods, rams, seals, and gaskets. Inspect in accordance with procedures in Para. 7.A.2.e. 7.B.2 Test each individual component of the blowout prevention system to be utilised in test facilities under shop conditions to rated working pressure utilising procedures outlined in Para.7.A.2.e. Following unitisation in the shop, test entire unit for proper operation using the hydraulic closing system. Test the closing system to 3000 psi. Pressure test each preventer and high pressure connector for low pressure (200 psi) leaks and to rated working pressure. Record the date and results of inspection and tests on the shipping tags. 7.B.3 After delivery to an offshore drilling unit, install the unitised blowout prevention system on a prepared test stump. A low pressure and rated working pressure test of each component as in the off-site procedure (Para. 7.B.2) should be repeated and properly recorded in the well log. Test record should include opening and closing times and hydraulic fluid volumes required for each function. Subsequent pressure tests should be limited to 70% of the rated working pressure of the blowout preventer stack or the anticipated surface pressure, whichever is greater. Full rated working pressure tests should be limited to one test following any major ram cavity repair work. 7.B.4 The blowout prevention system should be visually inspected and pressure tested in accordance with Para. 7.B.3 before returning on a well. SUBSEA TESTING 7.B.5 The blowout prevention system should be operated on each trip but not more than once every 24 hours during normal operations. The annular preventers need not be operated on each trip. They must, however, be operated in conjunction with the required pressure tests and at an interval not to exceed seven days. The periodic actuation test is not required for the blind or blind shear rams. These rams need only be tested when installed and prior to drilling out after each casing string has been set. A record of these tests should be maintained in the well log and should include closing and opening times and pressures and volumes of hydraulic fluid for each function. 7.B.6 Pressure tests of the subsea system should be conducted after installation, after setting casing, and before drilling into any known or suspected high pressure zones. Otherwise, these tests should be conducted at regular intervals but not

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more than once every week. On installation of the blowout preventer stack, each component including the high pressure connectors should be individually pressure tested at a low pressure (200 psi) and to the greater of 70 percent of rated working pressure or the maximum pressure expected in the upper part of the casing. Subsequent pressure tests may be limited to the lesser of 70 percent of the rated working pressure of the blowout preventers or 70 percent of the minimum internal yield strength rating of the upper part of the casing, provided the test pressure equals or exceeds the maximum pressure expected inside the upper part of the casing. An exception is the annular preventer which may be tested to 50 percent of its rated working pressure to minimise pack-off element wear or damage. A test plug or cup type tester should be used (refer to Section 7-A). Precautions should be taken not to expose the casing to test pressures in excess of its rated internal yield strength. A means should be provided to prevent pressure build up on the casing in the event the test tool seals leak. Actuation testing of pipe rams should not be performed on moving pipe. 7.B.7 The subsea blowout prevention system is dependent on surface actuated hydraulic, pneumatic, and electric controls. The design of this prevention system is dependent on water depth and environmental conditions and should have an adequate backup system to operate each critical function. It is equally important to pressure and operationally test this system concurrently with the blowout preventers and connectors.

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SECTION 7-C SEALING COMPONENTS—SURFACE INSTALLATIONS FLANGES AND HUBS 7.C.1 The following tabular data detail sizes in use on blow out preventers Rated Working Pressure psi 500 (0.5 M) 2,000 (2 M)

Flange or Hub Size in.

Minimum Vertical Bore in.

29 1/

29 1/

-

-

16 20 26 3/

16 3/ 4 21 1/ 4 26 3/

65 73 -

-

6 8 10 12 20 26 3/

1

7 / 16 9 11 13 5/ 8 20 3/ 4 26 3/

45 49 53 57 74 -

-

1

2

4

3,000 (3 M)

4

2

4

4

Ring-Joint Gaskets RX BX

5,000 (5 M)

6 10 13 5 / 8 16 3/ 4 18 3/ 4 21 1/

7 / 16 11 13 5/ 8 16 3/ 4 18 3/ 4 21 3/

46 54 -

160 162‡ 163 165

10,000 (10 M)

1

7 / 16 9 11 13 5/ 8 16 3/ 3 4 18 / 4 21 1/

1

7 / 16 9 11 13 5/ 8 16 3/ 3 4 18 / 4 21 1/

-

156 157 158 159 162 164 166

15,000 (15 M)

7 1/ 16 9 11 13 5/

7 1/ 16 9 11 13 5/

-

156 157 158 159

7 1/

7 1/

-

156

4

4

8

20,000 (20 M)

16

4

4

8

16

Notes: 1

* Replaces 20 /4" subsequent to January 1974. ‡ Replaces BX-161 subsequent to adoption of 5000 psi rated working pressure (10,000 psi test pressure) flange in lieu of 5000 psi rated working pressure (7500 psi test pressure) flange in June 1969.

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SECTION 7-D SEALING COMPONENTS—SUBSEA-INSTALLATIONS GENERAL 7.D.1 Operation of the subsea blowout preventer stack and marine riser system requires particular attention to the availability and correct usage of sealing components which are peculiar to subsea equipment. These non-API components are described in the following paragraphs. Manufacturers should be consulted for specifications and spare parts recommendations. Other sealing components are covered in Section 7-C. WELLHEAD CONNECTOR 7.D.2 The primary seal for the wellhead connector is a pressure energised metalto-metal type seal. Initial seal requires that the metal seal be coined into contact with the mating seal surfaces. These seals are not recommended for reuse. Some wellhead connectors are equipped with resilient secondary seal which may be energised should the primary seal leak. This seal should be utilised under emergency conditions only. MARINE RISER 7.D.3 The primary seal for the marine riser connector consists of resilient type O-Ring or lip-type seals. The primary seal for choke and kill line stab subs on the integral riser connector consists of pressure energised resilient seals or packing. Care should be taken to carefully clean and inspect all seals prior to running the marine riser. 7.D.4 The primary telescopic joint seal assembly consists of a hydraulic or pneumatic pressure energised resilient packing element. SUBSEA CONTROL SYSTEM 7.D.5 Primary hydraulic system seal between the male and female sections of the control pods is accomplished with resilient seals of the O-ring, pressure energised, or face sealing types. 7.D.6 The hydraulic junction boxes consist of stab subs or multiple check valve type quick disconnect couplings. The primary seals are O-rings. These seals should be inspected each time the junction box is disconnected. 7.D.7 The primary pod valve seals vary according to the manufacturer with both resilient and lapped metal-to-metal type seals used.

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SECTION 8 :

SURFACE BOP CONTROL SYSTEMS Page

8.0

BOP and Control Systems

1

8A

Closing Units - Surface Installations

7

8B

Closing Units - Subsea Installations

21

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WELL CONTROL for the Rig-Site Drilling Team SECTION 8 : SURFACE BOP CONTROL SYSTEMS

8.0 SURFACE BOP AND CONTROL SYSTEMS Figure 8.0.1 Land Rig Operation

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8-1


TYPICAL SURFACE BOP CONTROL SYSTEM T-SERIES

Figure 8.0.2

8-2

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TYPICAL SURFACE BOP CONTROL SYSTEM 1. Accumulators - Precharge per label. Warning! USE NITROGEN ONLY-DO NOT USE OXYGEN! Check every 30 days. 2. Accumulator Bank Isolation Valve -Manually operated, normally open. 3. Accumulator Bank Bleed Valve - Normally closed. 4. Accumulator Relief Valve Set at 3300 PSI. 5. Air Filter - Automatic Drain. Clean every 30 days. 6. Air Lubricator -Fill with SAE 10 lubricating oil, set for 6 drops per minute. Check oil level weekly. 7. Air Pressure - Gauge - 0 to 300PSI. 8. Hydro-pneumatic Pressure Switch -Automatically stops air operated pumps when pressure reaches 2900 PSI and starts pumps when pressure drops approximately 400 PSI. 9. Air Supply Valves -Normally open. Close when servicing air operated pumps. 10. Suction Valve, Air Operated Pumps -Normally open. Close when servicing pumps. 11. Suction Strainer, Air Operated Pumps - clean every 30 days. 12. Air Operated Pump. 13. Discharge Check Valve, Air Operated Pump. 14. Duplex or Triplex Pump Fill crankcase with SAE 20 oil for 40F to 115F ambient temperature range. Check oil level monthly. 15. Chain guard - Fill with SAE 40 oil for operation above 20F ambient temperature. Check oil level monthly. 16. Explosion-Proof Electric Motor. V4 Rev March 2002

17. Electric Pressure Switch Automatically stops pumps when accumulator pressure reaches 3000 PSI and starts pumps when pressure drops to 2700 PSI nominal. 18. Electric Motor Starter - Keep starter switch in “Auto” position except when servicing. TURN OFF power at main panel when servicing. 19. Suction Valve, Triplex or Duplex pump. Normally open. Close when servicing pump. 20. Suction Strainer, Triplex or Duplex pump - Clean every 30 days. 21. Discharge Check Valve, Duplex or Triplex Pump. 22. High Pressure Strainer Clean every 30 days. 23. Shut Off Valve - Normally close. Connection for separate operating fluid pump. 24. Manifold Regulator Regulates operating pressure to ram preventers and gate valves. Manually adjustable from 0 to 1500 PSI, TR™ Regulator contains internal by-pass for pressures up to 3000 PSI or 5000 PSI. (See 39 option)

of the annular operating pressure. Adjustable from 0 to 1500 PSI. TR Regulator can provide regulation up to 3000 PSI for Cameron Type D annulars and contains a manual override to prevent loss of operating pressure should remote control pilot pressure be lost. 31. Annular Pressure Gauge - 0 to 3000 PSI. (0-6000 PSI for Cameron D Annulars.) 32. Annular Pressure Transmitter - Hydraulic input, 3-15 PSI air output. 33. Accumulator Pressure Transmitter - 0 to 6000 PSI hydraulic input, 315 PSI air output. 34. Manifold Pressure Transmitter - 0 to 10,000 PSI hydraulic input,3- 15 PSI air output. (Transmitter converts hydraulic pressure to air pressure and sends a calibrated signal to corresponding air receiver gauges on the Driller’s air operated remote control panel.) 35. Air Junction Box - Used for connecting the air cable from the air operated remote control panels.

25. Manifold Regulator Internal Override Valve - Normally in low-pressure (handle left) position. For operating pressures above l 500 PSI (ram preventers and gate valves), move to high pressure position (handle right).

36. Reservoir - Stores operating fluid at atmospheric pressure. Fill to within 8 inches from top with Welkic™ 10 or SAE 10 oil.

26. 5,000 PSI W.P. Sub-Plate Mounted Four-way Control Valve - Direct the flow of operating fluid pressure to the preventers and gate valves. NEVER leave in the centre position.

38. Sight glass, fluid level (T-Series units).

27. Manifold Bleeder Valve. 28. Accumulator Pressure Gauge - 0 to 6000 PSI.

37. Clean out man-way (T-Series units).

Option- Available on units with 5000 PSI working pressure manifold valves and piping. 39. By-pass Valve Hydro-pneumatic pressure switch.

29. Manifold Pressure Gauge - 0 to 10,000 PSI.

40. Normal Pressure Isolation Valve -Normally open. Close for pressure above 3000 PSI. This feature can be used for shearing.

30. Annular Regulator Provides independent regulation

41. Manifold Protector Relief Valve - Set at 5500 PSI. 8-3


SYSTEM DESCRIPTION GENERAL A Blowout Preventer (BOP) Control System is a high pressure hydraulic power unit fitted with directional control valves to safely control kicks and prevent blowouts during drilling operations. A typical system offers a wide variety of equipment to meet the customer’s specific operational and economic criteria. The following text gives a brief description of the equipment and some of its major components. Figure 8.0.3 ACCUMULATOR UNIT MODULE

The primary function of the accumulator unit module is to provide the atmospheric fluid supply for the pumps and storage of the high pressure operating fluid for control of the BOP stack. It includes accumulators, reservoir, accumulator piping and a master skid for mounting of the air operated pumps, electric motor driven pumps and the hydraulic control manifold. Accumulators Accumulators are ASME coded pressure vessels for storage of high pressure fluid. These accumulators are available in a variety of sizes, types, capacities and pressure ratings. The two (2) basic types are bladder and float which are available in cylindrical or ball styles. The accumulators can either be bottom or top loading. Top loading means the bladder or float can be removed from the top while it is still mounted on the accumulator unit. Bottom loading accumulators must be removed from the accumulator unit to be serviced. Bladder and buoyant float type accumulators can be repaired in the field without destroying their stamp of approval.

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Reservoir A rectangular reservoir is provided for storage of the atmospheric fluid supply for the high pressure pumps. It contains baffles, fill and drain ports and troubleshooting inspection ports. For filling and cleaning procedures see the Maintenance section. It should be able to store 2 times the capacity of the usable fluid capacity. Accumulator Piping This piping connects the high pressure discharge lines of the pumps to the accumulators and the hydraulic manifold. It is comprised of 1 or 1-1/2" Schedule 80 or 160 pipe, isolator valves and a 3300 psi relief valve to protect the accumulators from being over pressured. Cylindrical type accumulators are mounted on machined headers to minimise line restrictions and leaks. AIR PUMP ASSEMBLY The air pump assembly consists of one (1) or more air operated hydraulic pumps connected in parallel to the accumulator piping to provide a source of high pressure operating fluid for the BOP Control System. These pumps are available in a variety of sizes and ratios. Figure 8.0.4

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8-5


ELECTRIC PUMP ASSEMBLY The electric pump assembly consists of a duplex or triplex reciprocating plunger type pump driven by an explosion-proof electric motor. It is connected to the accumulator piping to provide a source of high pressure operating fluid for the BOP Control System. It is available in a variety of horsepower and voltage ranges.

Figure 8.0.5

8-6

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SECTION 8.A CLOSING UNITS—SURFACE INSTALLATIONS ACCUMULATOR REQUIREMENTS General 8.A.1 Accumulator bottles are containers which store hydraulic fluid under pressure for use in effecting blowout preventer closure. Through use of compressed nitrogen gas, these containers store energy which can be used to effect rapid preventer closure. There are two types of accumulator bottles in common usage, separator and float types. The separator type uses a flexible diaphragm to effect positive separation of the nitrogen gas from the hydraulic fluid. The float type utilises a floating piston to effect separation of the nitrogen gas from the hydraulic fluid. Volumetric Capacity 8.A.2 As a minimum requirement, all blowout preventer closing units should be equipped with accumulator bottles with sufficient volumetric capacity to provide the usable fluid volume (with pumps inoperative) to close one pipe ram and the annular preventer in the stack plus the volume to open the hydraulic choke line valve. 8.A.3 Usable fluid volume is defined as the volume of fluid recoverable from an accumulator between the accumulator operating pressure and 200 psi above the precharge pressure. The accumulator operating pressure is the pressure to which accumulators are charged with hydraulic fluid. 8.A.4 The minimum recommended accumulator volume (nitrogen plus fluid) should be determined by multiplying the accumulator size factor (refer to Table 8-A) times the calculated volume to close the annular preventer and one pipe ram plus the volume to open the hydraulic choke line valve. TABLE 8. A Accumulator Operating Pressure psi

Minimum Recommended Precharge Pressure psi

1500 2000 3000

750 1000 1000

Notes:

Usable Fluid Volume* (fraction of bottle size)

Accumulator Size Factor*

1 / 1 8 / 1 3 / 2

8 3 2

*Based on minimum discharge pressure of 1200 psi.

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8-7


Response Time 8.A.5 The closing system should be capable of closing each ram preventer within 30 seconds. Closing time should not exceed 30 seconds for annular preventers smaller than 18 3/4 inches and 45 seconds for annular preventers 18 3/4 inches and larger. Operating Pressure and Precharge Requirements for Accumulators 8.A.6 No accumulator bottle should be operated at a pressure greater than its rated working pressure. 8.A.7. The precharge pressure on each accumulator bottle should be measured during the initial closing unit installation on each well and adjusted if necessary (refer to Para. 8.A.4). Only nitrogen gas should be used for accumulator precharge. The precharge pressure should be checked frequently during well drilling operations. Requirements for Accumulator Valves, Fittings, and Pressure Gauges 8.A.8 Multi-bottle accumulator banks should have valving for bank isolation. An isolation valve should have a rated working pressure at least equivalent to the designed working pressure of the system to which it is attached and must be in the open position except when accumulators are isolated for servicing, testing, or transporting (refer to Fig. 8.A.1). Accumulator bottles may be installed in banks of approximately 160 gallons capacity if desired, but with a minimum of two banks. 8.A.9 The necessary valves and fittings should be provided on each accumulator bank to allow a pressure gauge to be readily attached without having to remove all accumulator banks from service. An accurate pressure gauge for measuring the accumulator precharge pressure should be readily available for installation at any time. CLOSING UNIT PUMP REQUIREMENTS Pump Capacity Requirements 8.A.10 Each closing unit should be equipped with sufficient number and sizes of pumps to satisfactorily perform the operation described in this paragraph. With the accumulator system removed from service. The pumps should be capable of closing the annular preventer on the size drill pipe being used, plus opening the hydraulically operated choke line valve and obtain a minimum of 200 psi pressure above accumulator precharge pressure on the closing unit manifold within two (2) minutes or less.

8-8

V4 Rev March 2002


Pump Pressure Rating Requirements 8.A.11 Each closing unit must be equipped with pumps that will provide a discharge pressure equivalent to the rated working pressure of the closing unit. Pump Power Requirements 8.A.l2 Power for closing unit pumps must be available to the accumulator unit at all times, such that the pump will automatically start when the closing unit manifold pressure has decreased to less than 90 percent of the accumulator operating pressure. 8.A.13 Two or three independent sources of power should be available on each closing unit. Each independent source should be capable of operating the pumps at a rate that will satisfy the requirement described in Para. 8.A.10. The dual source power system recommended is an air system plus an electrical system. Minimum recommendations for the dual air system and other acceptable but less preferred dual power source systems are as follows: a.

A dual air/electrical system may consist of the rig air system (provided at least one air compressor is driven independent of the rig compound) plus the rig generator (refer to Fig. 8.A.2).

b.

A dual air system may consist of the rig air system (provided at least one air compressor is driven independent of the rig compound) plus an air storage tank that is separated from both the rig air compressors and the rig air storage tank by check valves. The minimum acceptable requirements for the separate air storage tank are volume and pressure which will permit use of only the air tank to operate the pumps at a rate that will satisfy the operation described in the pump capacity requirements (refer to Para. 8.A.10).

c.

A dual electrical system may consist of the normal rig generating system and a separate generator (refer to Fig. 8.A.3).

d.

A dual air/nitrogen system may consist of the rig air system plus bottled nitrogen gas (refer to Fig.8.A.4).

e.

A dual electrical/nitrogen system may consist of the rig generating system and bottled nitrogen gas (refer to Fig. 8.A.5).

8.A.14 On shallow wells where the casing being drilled through is set at 500 feet or less and where surface pressures less than 200 psi are expected, a backup source of power for the closing unit is not essential.

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REQUIREMENTS FOR CLOSING UNIT VALVES FITTINGS, LINES, AND MANIFOLD Required Pressure Rating 8.A.15 All valves and fittings between the closing unit and the blowout preventer stack should be of steel construction with a rated working pressure at least equal to the working pressure rating of the stack up to 3000 psi. Refer to API Spec 6A: Specification for Wellhead Equipment* for test pressure requirements. All lines between the closing unit and blowout preventer should be of steel construction or an equivalent flexible, fire-resistant hose and end connections with a rated working pressure equal to the stack pressure rating up to 3000 psi. Valves Fittings and other Components Required 8.A.16 Each installation should be equipped with the following:

8 - 10

a.

Each closing unit manifold should be equipped with a full-opening valve into which a separate operating fluid pump can be easily connected (refer to Fig. 8.A.1).

b.

Each closing unit should be equipped with sufficient check valves or shut-off valves to separate both the closing unit pumps and the accumulators from the closing unit manifold and to isolate the annular preventer regulator from the closing unit manifold.

c.

Each closing unit should be equipped with accurate pressure gauges to indicate the operating pressure of the closing unit manifold, both upstream and downstream of the annular preventer pressure regulating valve.

d.

Each closing unit should be equipped with a pressure regulating valve to permit manual control of the annular preventer operating pressure.

e.

Each closing unit equipped with a regulating valve to control the operating pressure on the ram type preventers should be equipped with a bypass line and valve to allow full accumulator pressure to be placed on the closing unit manifold, if desired.

f.

Closing unit control valves must be clearly marked to indicate (1) which preventer or choke line valve each control valve operates, and (2) the position of the valves (i.e., open, closed, neutral). Each blowout preventer control valve should be turned to the open position (not the neutral position) during drilling operations. The choke line hydraulic valve should be turned to the closed position during normal operations. The control valve that operates the blind rams should be equipped with a cover over the manual handle to avoid unintentional operation.

V4 Rev March 2002


g.

Each annular preventer may be equipped with a full-opening plug valve on both the closing and opening lines. These valves should be installed immediately adjacent to the preventer and should be in the open position at all times except when testing the operating lines. This will permit testing of operating lines in excess of 1500 psi without damage to the annular preventer if desired by the user.

*Available from American Petroleum Institute. Production Department, 2535 One Main Place Dallas TX 75202-3904.

REQUIREMENTS FOR CLOSING UNIT FLUIDS AND CAPACITY 8.A.17 A suitable hydraulic fluid (hydraulic oil or fresh water containing a lubricant) should be used as the closing unit control operating fluid. Sufficient volume of glycol must be added to any closing unit fluid containing water if ambient temperatures below 32 F are anticipated. The use of diesel oil, kerosene, motor oil, chain oil. or any other similar fluid is not recommended due to the possibility of resilient seal damage. 8.A.18 Each closing unit should have a fluid reservoir with a capacity equal to at least twice the usable fluid capacity of the accumulator system. CLOSING UNIT LOCATION AND REMOTE CONTROL REQUIREMENTS 8.A.19 The main pump accumulator unit should be located in a safe place which is easily accessible to rig personnel in an emergency. It should also be located to prevent excessive drainage or flow back from the operating lines to the reservoir. Should the main pump accumulator be located a substantial distance below the preventer stack, additional accumulator volume should be added to compensate for flow back in the closing lines. 8.A.20 Each installation should be equipped with a sufficient number of control panels such that the operation of each blowout preventer and control valve can be controlled from a position readily accessible to the driller and also from an accessible point at a safe distance from the rig floor.

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CLOSING UNIT PUMP CAPABILITY TEST 8.A.21 Prior to conducting any tests, the closing unit reservoir should be inspected to be sure it does not contain any drilling fluid, foreign fluid, rocks, or other debris. The closing unit pump capability test should be conducted on each well before pressure testing the blowout preventer stack. This test can be conveniently scheduled either immediately before or after the accumulator closing time test. Test should be conducted according to the following procedure: a.

Position a joint of drill pipe in the blowout preventer stack.

b.

Isolate the accumulators from the closing unit manifold by closing the required valves.

c.

If the accumulator pumps are powered by air, isolate the rig air system from the pumps. A separate closing unit air storage tank or a bank of nitrogen bottles should be used to power the pumps during this test. When a dual power source system is used, both power supplies should be tested separately.

d.

Simultaneously turn the control valve for the annular preventer to the closing position and turn the control valve for the hydraulically operated valve to the opening position.

e.

Record the time (in seconds) required for the closing unit pumps to close the annular preventer plus open the hydraulically operated valve and obtain 200 psi above the precharge pressure on the closing unit manifold. It is recommended that the time required for the closing unit pumps to accomplish these operations not exceed two minutes.

f.

Close the hydraulically operated 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.

ACCUMULATOR TESTS Accumulator Precharge Pressure Test 8.A.22 This test should be conducted on each well prior to connecting the closing unit to the blowout preventer stack. Test should be conducted as follows-

8 - 12

a.

Open the bottom valve on each accumulator bottle and drain the hydraulic fluid into the closing unit fluid reservoir.

b.

Measure the nitrogen precharge pressure on each accumulator bottle, using an accurate pressure gauge attached to the precharge measuring port, and adjust if necessary. V4 Rev March 2002


Accumulator Closing Test 8.A.23 This test should be conducted on each well prior to pressure testing the blowout preventer stack. Test should be conducted as follows: a.

Position a joint of drill pipe in the blow out preventer stack.

b.

Close off the power supply to the accumulator pumps.

c.

Record the initial accumulator pressure. This pressure should be the designed operating pressure of the accumulators. Adjust the regulator to provide 1500 psi operating pressure to the annular preventer.

d.

Simultaneously turn the control valves for the annular preventer and for one pipe ram (having the same size ram as the pipe used for testing) to the closing position and turn the control valve for the hydraulically operated valve to the opening position.

e.

Record the time required for the accumulators to close the preventers and open the hydraulically operated valve. Record the final accumulator pressure (closing unit pressure). This final pressure should be at least 200 psi above the precharge pressure.

f.

After the preventers have been opened, recharge the accumulator system to its designed operating pressure using the accumulator pumps.

V4 Rev March 2002

8 - 13

FLUID RESERVOIR

8 - 14

PUMP

PUMP

CONNECTION FOR ANOTHER PUMP

FULL-OPENING VALVE

TEST FLUID LINE

BLOWOUT PREVENTER TEST LINE

TO RAM BLOWOUT PREVENTERS

VALVE AND GAUGE

VALVE AND GAUGE

PRESSURE REGULATOR (0-1500 PSI)

CONNECTION FOR ANOTHER PUMP

NOTE: PLUG VALVE IN CLOSING LINE ADJACENT TO ANNULAR PREVENTER TO FACILITATE LOCKING CLOSING PRESSURE TO ANNULAR ON PREVENTER. BLOWOUT PREVENTER

RELIEF VALVE

FULL OPENING VALVE

CHECK VALVE

TO CHOKE LINE VALVE

Figure 8.A.1 EXAMPLE BLOWOUT PREVENTER CLOSING UNIT ARRANGEMENT

FOUR-WAY VALVES (NOTE: SHOULD NOT CONTAIN CHECK VALVE AND SHOULD BE IN POWER ON POSITION)

REGULATOR BY-PASS LINE

CHECK VALVE

PRESSURE REGULATOR (1500-3000 PSI)

FULL-OPENING VALVES

ACCUMULATOR BANKS

NEEDLE VALVES


SECTION 8 : SURFACE BOP CONTROL SYSTEMS

V4 Rev March 2002


TO RIG

CHECK VALVE

AIR COMPRESSORS

CLOSING UNIT PUMPS

STORAGE TANK FOR RIG AIR

TO CLOSING UNIT MANIFOLD AND ACCUMULATORS

ELECTRICAL POWER SUPPLY

Figure 8.A.2 EXAMPLE REDUNDANT AIR/ELECTRIC SYSTEMS FOR OPERATING CLOSING UNIT PUMPS

RIG GENERATOR

CLOSING UNIT PUMPS


SEPARATE GENERATOR

Figure 8.A.3 EXAMPLE REDUNDANT ELECTRICAL SYSTEMS FOR OPERATING CLOSING UNIT PUMPS

V4 Rev March 2002

8 - 15


TO RIG CHECK VALVE

CHECK VALVE


OPTIONAL

CLOSING UNIT PUMPS

STORAGE TANK FOR RIG AIR

NITROGEN

Figure 8.A.4 EXAMPLE REDUNDANT AIR/NITROGEN SYSTEMS FOR OPERATING CLOSING UNIT PUMPS

RIG GENERATOR

CLOSING UNIT PUMPS


OPTIONAL

NITROGEN

Figure 8.A.5 EXAMPLE REDUNDANT ELECTRIC/NITROGEN SYSTEMS FOR OPERATING CLOSING UNIT PUMPS

8 - 16

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Figure 8.0.6 ACCUMULATOR SIZINGS

Calculation of Accumulator Size The volume of the accumulator system as calculated by using “Boyle’s law”: P1V1 = P2V2 where P1 P2

= =

Maximum pressure of the accumulator when completely charged Minimum pressure left in accumulator after use. (Recommended minimum is1200 psi) V = Total volume of accumulator (fluid and nitrogen) V1 = Nitrogen gas volume in accumulator at maximum pressure P1. V2 = Nitrogen gas volume in accumulator at minimum pressure P2. V2 = V, plus usable fluid maximum to minimum pressure. V2-V1 = Total usable fluid with safety factor usually 50% included. 3000 psi system precharged to 1000 psi; V = 3V1

V4 Rev March 2002

8 - 17


Surface Accumulators (Refer to Fig 8.0.6) For the purpose of simplicity, the effects of temperature and nitrogen gas compressibility will be ignored and Boyle’s gas law applied to determine the volume of nitrogen present in the accumulator bottle when fully charged and when usable hydraulic fluid has been expelled to operate the BOP functions. In an 11 gallon accumulator bottle the volume of nitrogen it contains before any fluid is pumped in will be 10 gallons (the rubber bladder occupies a volume of 1 gallon). According to Boyle’s gas law: P1 x V1 = P2 x V2 and also P1 x V1 = P3 x V3 where:P1 = nitrogen precharge pressure of 1000 psi P2 = minimum operating pressure of 1200 psi P3 = maximum operating pressure of 3000 psi V1 = bladder internal volume at precharge pressure (11 gal - 1 gal) V2 = bladder internal volume at minimum operating pressure, P2 (in gals) V3 = bladder internal volume at maximum operating pressure, P3 (in gals) therefore:1000 psi x 10 gals = 1200 psi x V2 and 1000 psi x 10 gals = 3000 psi x V3 giving V2 = 1000 psi x 10 gals = 8.33 gals 1200 psi and V3 = 1000 psi x 10 gals = 3.33 gals 3000 psi The usable volume of hydraulic fluid expelled from the bottle as the nitrogen expands from V3 (3.33 gals) at 3000 psi to V2 (8.33 gals) at 1200 psi will be equal to:V2 - V3 = 8.33 gals - 3.33 gals = 5 gals 8 - 18

V4 Rev March 2002


Subsea Accumulators The nitrogen precharge pressure must be increased in the subsea accumulator bottles in order to account for the hydrostatic pressure of the hydraulic fluid in the power fluid supply hose, when calculating the amount of usable fluid volume. As an added safety factor the sea water gradient is used for this purpose, i.e. .445 psi/ft. If operating in 1500 ft of water, the hydrostatic pressure would be:1500 ft x .445 psi/ft = 667.5 or 668 psi (rounded off). Thus the nitrogen precharge would need to be increased by 668 psi. i.e. 1000 psi + 668 psi = 1668 psi. therefore:P1 = nitrogen precharge pressure of 1668 psi (1000 psi + 668 psi) P2 = minimum operating pressure of 1868 psi (1200 psi + 668 psi) P3 = maximum operating pressure of 3668 psi (3000 psi + 668 psi) V1 = bladder internal volume at precharge pressure (11 gal - 1 gal) V2 = bladder internal volume at minimum operating pressure, P2 (in gals) V3 = bladder internal volume at maximum operating pressure, P3 (in gals) therefore:1668 psi x 10 gals = 1868 psi x V2 and 1668 psi x 10 gals = 3668 psi x V3 giving:V2 = 1668 psi x 10 gals = 8.93 gals and V3 = 1668 psi x 10 gals = 4.55 gals 1868 psi 3668 psi The usable volume of hydraulic fluid per subsea bottle in 1500 ft of water would be the difference between these two volumes. V2 - V3 = 8.93 gals - 4.55 gals = 4.38 gals. Application of the above calculation now makes it possible to determine the total number of accumulator bottles required both on the surface and subsea, given the following opening and closing volumes of hydraulic fluid for a typical 18.75 inch subsea BOP stack Annular preventer Ram preventer Failsafe valves V4 Rev March 2002

44 gals to close 17.1 gals to close 0.6 gals to close

44 gals to open 15.6 gals to open 0.6 gals to open 8 - 19


Assuming that company policy is to have sufficient subsea accumulator capacity to close: 1 annular 1 ram preventer 4 failsafe valves then the usable volume required will be 44 gal + 17.1 gal + (4 x 0.6 gal) = 63.5 gals and since each bottle can deliver 4.38 gals then: 63.5 gals = 14.49 or 15 bottles will be required subsea. 4.38 gal/bottle If the BOP stack consists of: 2 annular preventers 4 ram preventers 8 failsafe valves then the total volume of hydraulic fluid required to open and close all of the BOP functions together will be: CLOSE OPEN 2 x annular preventers 2 x 44 gal = 88 gal 2 x 44 gal = 88 gal 4 x ram preventers 4 x 17.1 gal = 68.4 gal 4 x 15.6 gal = 62.4 gal 8 x failsafe valves 8 x 0.6 gal = 4.8 gal 8 x 0.6 gal = 4.8 gal ––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––– TOTAL 161.2 gal 155.2 gal Including a 1.5 safety factor will give a grand total of (161.2 gal + 155.2 gal) x 1.5 = 474.6 gals. Since 63.5 gals are available subsea, the surface accumulators will have to supply (474.6 gal - 63.5 gal) = 411.1 gals. As calculated above, the usable fluid from each surface accumulator bottle is 5 gals therefore: 411.1 gals = 82.22 or 83 bottles will be required on surface. 5 gal/bottle

8 - 20

V4 Rev March 2002


SECTION 8-B CLOSING UNITS—SUBSEA INSTALLATIONS VARIANCE FROM SURFACE INSTALLATIONS 8.B.1 Closing unit systems for subsea installations are basically the same as those used in surface installations except more accumulator volume is normally required and some of the accumulator bottles may be mounted on the subsea blowout preventer stack. ACCUMULATOR REQUIREMENTS Volumetric Capacity 8.B.2 As a minimum requirement, closing units for subsea installations should be equipped with accumulator bottles with sufficient volumetric capacity to provide the usable fluid volume (with pumps inoperative) to close and open the ram preventers and one annular preventer. Usable fluid volume is defined as the volume of fluid recoverable from an accumulator between the accumulator operating pressure and 200 psi above the precharge pressure. 8.B.3 In sizing subsea mounted bottles, the additional precharge pressure required to offset the hydrostatic head of the sea-water column and the effect of subsea temperature should be considered. Response Time 8.B.4 The closing system should be capable of closing each ram preventer within 45 seconds. Closing time should not exceed 60 seconds for annular preventers. Requirements for Accumulator Valves 8.B.5 Multi-bottle accumulator banks should have valving for bank isolation. The isolation valves should have a rated working pressure at least equivalent to the designed working pressure of the system to which they are attached. The valves must be in the open position except when the accumulators are isolated for servicing, testing, or transporting. Accumulator Types 8.B.6 Both separator or float type accumulators (refer to Para. 9.A.l) may be used.

V4 Rev March 2002

8 - 21


HYDRAULIC FLUID CONTROL MIXING SYSTEM 8.B.7 The hydraulic fluid reservoir should be a combination of two storage sections; one section containing mixed fluid to be used in the operation of the blowout preventers, and the other section containing the concentrated watersoluble hydraulic fluid to be mixed with water to form the mixed hydraulic fluid. This mixing system should be automatically controlled so that when the mixed fluid reservoir level drops to a certain point, the mixing system will turn on and water and hydraulic fluid concentrate will be mixed into the mixed fluid reservoir. The mixing system should be designed to mix at a rate equal to the total pump output. PUMP REQUIREMENTS 8.B.8 A subsea closing unit control system should include a combination of air and electric pumps. A minimum of two air pumps should be in every system along with one or two electric powered triplex pumps. The combination of air and electric pumps should be capable of charging the entire accumulator system from the precharge pressure to the maximum rated charge pressure in fifteen minutes or less. The pumps should be installed so that when the accumulator pressure drops to 90 percent of the preset level, a pressure switch is triggered and the pumps are automatically turned on. CENTRAL CONTROL POINT 8.B.9 A subsea closing unit control system should have a central control point. For a hydraulic system, this should be a manifold capable of controlling all the hydraulic functions on the blowout preventer stack. The hydraulic control system should consist of a power section to send hydraulic fluid to subsea equipment and a pilot section to transmit signals subsea via pilot lines. When a valve on the control manifold is operated, a signal is sent subsea to a control valve, which when opened allows hydraulic fluid from the power fluid section to operate the blowout preventers. Pressure regulators on the surface control manifold send pilot signals to subsea regulators to control the pressure of the hydraulic fluid at the preventers. The surface control system should also include a flow meter which, by a measure of the volume of fluid going to a particular function, will indicate if that function is operating properly. The hydraulic manifold should be located in a safe but readily accessible area. 8.B.10 An Electro-hydraulic system should have a central control point which interfaces various signals electronically and sends one set of signals electrically to the subsea solenoid valves, which direct the flow of hydraulic fluid to operate a blowout preventer function. In this system, a flow meter should be used to provide an indication of the proper flow of hydraulic fluid and proper operation of the blow out preventer.

8 - 22

V4 Rev March 2002


OTHER CONTROL PANELS 8.B.11 Subsea control systems should have at least one remote control panel. The panel should have a schematic outline of the blowout preventer stack and provide for remote panel activation. There should be a remote control panel located on the rig floor adjacent to the driller’s station. This panel should comply with API RP 500B: Recommended Practice for Classification of Areas for Electrical Installations at Drilling Rigs and Production Facilities on Land and on Marine Fixed and Mobile Platforms.* Another remote panel is sometimes located in the toolpusher’s office. One control station should be located at least 50 feet from the centre line of the wellbore. HOSE AND HOSE REELS 8.B.12 A hydraulic hose bundle may consist of pilot hoses which have an inside diameter of 3/16" or 1/8" or both, and a power hose which is one inch inside diameter. The pilot hoses, as previously described, carry the signals to the subsea valves on the blowout preventer stack, while the main hydraulic fluid is supplied through a hose or rigid line to the pod and accumulators on the blowout preventer stack. The working pressure rating of the hose bundle should equal or exceed the working pressure rating of the control system. For an Electro-hydraulic system, electrical cables are run subsea to the solenoid valves. The hydraulic power supply line may be integrated into an electrical cable bundle or may be run separately. 8.B.13 The hose reels should be equipped so that some functions are operable while running or pulling the blowout preventer stack or lower marine riser package. Recommended functions to be operable at these times are the stack connector, riser connector, one set of pipe rams, pod latches, and, if applicable, ram locks. SUBSEA CONTROL PODS 8.B.14 There should be two completely redundant control pods on the blowout preventer stack after drilling out from under the surface casing. Each control pod should contain all necessary valves and regulators to operate the blowout preventer stack functions. The control pods may be retrievable or non-retrievable. The hoses from each control pod should be connected to a shuttle valve that is connected to the function to be operated. A shuttle valve is a slide valve with two inlets and one outlet which prevents movement of the hydraulic fluid between the two redundant control pods.

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8 - 23

SECTION 9 :

SUBSEA BOP CONTROL SYSTEMS AND MARINE RISER SYSTEMS Page

9. 1

Subsea BOP Control Systems

1

9. 2

Marine Riser Systems

35

V4 Rev March 2002

WELL CONTROL for the Rig-Site Drilling Team SECTION 9 : SUBSEA BOP CONTROL SYSTEMS & MARINE RISER SYSTEMS

9 .1 SUBSEA BOP CONTROL SYSTEMS INTRODUCTION Every component in a blowout preventer assembly is operated hydraulically by moving a piston up and down or back and forth. Thus the function of a BOP control system is to direct hydraulic fluid to the appropriate side of the operating piston and to provide the means for fluid on the other side of the piston to be expelled. On land, jack-up or platform drilling operations the control of the BOP is easily achieved in a conventional manner by coupling each BOP function directly to a source of hydraulic power situated at a safe location away from the wellhead. Operation of a particular BOP function is then accomplished by directing hydraulic power from the control unit back and forth along two large bore lines to the appropriate operating piston. This system uses the minimum number of controlling valves to direct the hydraulic fluid to the required function. It also enables the returning fluid to be returned to the control unit for further use. For subsea drilling operations, it is necessary to control larger, more complex BOP assemblies which are remotely located on the sea-bed. In this instance, direct control cannot be applied since the resulting control lines connecting the BOPs to the surface would be prohibitively large to handle. Reaction times would also be unacceptable due to the longer distances to the BOP functions and the consequent pressure drop. In order to overcome these problems indirect operating systems have been developed. There are two types - hydraulic and multiplex electro-hydraulic of which the indirect hydraulic system is by far the most common. INDIRECT HYDRAULIC SYSTEM This reduces the size of the control umbilical by splitting the hydraulic control functions into two • Transmitting hydraulic power to the BOP down a large diameter line. • Transmitting hydraulic signals down smaller lines to pilot valves which in turn direct the operating power fluid to the appropriate BOP function. The pilot valves are located in control pods on the BOP stack. In order to provide a complete back-up of the subsea equipment there are two control pods - usually referred to as the blue and the yellow pods. No attempt is made to recover the hydraulic power fluid once it has been used to operate a function since this would increase the number of lines required in the umbilical. Instead the fluid is vented subsea from the control pod. V4 Rev March 2002

9-1


MULTIPLEX ELECTRO-HYDRAULIC SYSTEM As greater water depths were encountered the problems of umbilical handling and reaction times became significant. In order to overcome them the hydraulic lines controlling the pilot valves were replaced by separate electrical cables which operate solenoid valves. These valves then send a hydraulic signal to the relevant pilot valve which in turn is actuated and directs power fluid to its associated BOP function. The time division multiplexing system provides simultaneous execution of commands and results in a relatively compact electrical umbilical. This typically consists of four power conductors, five conductors for signal transmission and additional back-up and instrumentation lines. With the armoured sheath the umbilical has a resulting diameter of some 1.5 inches with a weight of about 3 Ib/ ft in air. ACOUSTIC SYSTEM In addition to either of the primary control methods mentioned above, the subsea BOP stack can also be equipped with an acoustic emergency back-up system. In principle this is similar to the other two systems but with the hydraulic or electrical commands to the pilot valves being replaced with acoustic signals. Being a purely back-up system the number of commands is limited to those which might be required in an absolute emergency. INDIRECT HYDRAULIC BOP CONTROL SYSTEM The main manufacturers of control systems are Cameron Iron Works, NL Shaffer, Koomey, and the Valvcon Division of Hydril. The NL Shaffer and Koomey systems will be discussed in detail to illustrate the general concept since these are probably the most common types. 9.1.1 OVERVIEW Fig 9 .1 shows the general arrangement. Fluid used to operate the functions on the BOP stack is delivered from the hydraulic power unit on command from the central hydraulic control manifold. This contains the valves which direct pilot pressure to the pilot valves in the subsea control pods and which are operated either manually or by solenoid actuated air operators. In this way the manifold can be controlled remotely via the actuators from the master electric panel (usually located on the rig floor) or from an electric minipanel (located in a safe area). The system may include several remote mini-panels if desired. An electric power pack with battery back-up provides an independent supply to the panels via the central control manifold.

9-2

V4 Rev March 2002


The pilot fluid is sent to the subsea control pods through individual, small diameter hoses bundled around the larger diameter hose which delivers the power fluid. In order to provide complete redundancy for the subsea portion of the control system there are two independent hydraulic hose bundles and two independent control pods. The hydraulic hose bundles (or umbilicals) are stored on two hose reels, each of which is equipped with a special manual control manifold so that certain stack functions can be operated whilst the stack is being run. Hydraulic jumper hose bundles connect the central hydraulic control manifold to the two hose reels. Each umbilical is run over a special sheave and terminates in its control pod. For repair purposes each pod along with its umbilical can be retrieved and run independently of the BOP stack. In order to do this, the pod and umbilical is run on a wireline which is usually motion compensated. In some designs of control system, the umbilical is run attached to the riser in order to give it more support and reduce fatigue at hose connections. The pod is still attached to a wireline for retrieval purposes. This design has the advantage of not having to handle the umbilicals whenever the pod is pulled but has the disadvantage of requiring more subsea remote hydraulic connections. Guidance of the pod is provided by the guidewires and guideframe as shown. Fig 9.2 is a block diagram of the hydraulic flow system for a stack function. The hydraulic fluid is prepared and stored under pressure in the accumulators. Some accumulators (usually two) are dedicated to storing fluid for use in the pilot line network and the remaining accumulators contain the fluid that is used to power the various BOP functions.

V4 Rev March 2002

9-3


Figure 9.1

9-4

V4 Rev March 2002


CONCENTRATE

WATER

MIXED FLUID RESEVOIR ISOLATION VALVE

AIR PUMP (PILOT FLUID) CHECK VALVE

AIR & ELECTRIC PUMPS (POWER FLUID)

ACCUMULATORS (POWER FLUID)

ACCUMULATORS (PILOT FLUID)

POD SELECT VALVE

VENT

JUNCTION BOX (BLUE)

JUNCTION BOX (YELLOW)

HOSE REEL (BLUE)

HOSE REEL (YELLOW) SHUTTLE VALVE

SPM PILOT

ISOLATION VALVE

SPM PILOT

ISOLATION VALVE

REGULATOR

ACCUMULATORS (STACK MOUNTED) SHUTTLE VALVE

KEY

BOP STACK

PILOT psi ACCUMULAT OR psi REGULATOR psi VENT psi

Figure 9.2 SUBSEA CONTROL SYSTEM - BLOCK DIAGRAM

V4 Rev March 2002

9-5


The power fluid is routed to the subsea control pod selected by the pod selector valve which is located in the central hydraulic control manifold. The line to the non-selected pod is vented. When power fluid reaches the pod, it is combined with fluid stored at the same pressure in subsea accumulators, located on the BOP stack. The pressure of the combined fluid is then reduced, to that required to operate the stack function, by a subsea regulator situated in the control pod. Adjustment of this regulator is performed from the surface via dedicated pilot and read-back lines in the hose bundle. Pilot fluid is always directed to both pods at the same time. When the pilot fluid for a particular function reaches each pod it lifts the spindle of its associated SPM (sub plate mounted) pilot valve. In the pod to which the power fluid has been sent this will allow the fluid to pass through the SPM valve and be routed to the stack function via a shuttle valve. A summary of this operating sequence is shown in Fig 9.3. 9.1.2 OPERATING SEQUENCE A more detailed description of the sequence of events that occur when a function is operated will now be given with reference to the flow diagram in Figs 9.3a b and c. Each piece of equipment on the BOP stack has a corresponding pilot control valve on the central hydraulic control manifold which actuates the appropriate SPM valve. The control valve is a four-way, three position valve and can be functioned manually or by an air operator. CLOSE FUNCTION In Fig 9.3a one of the BOP rams is being closed using the drillers master control panel. Pushing the ‘close’ button on this panel actuates the solenoid valves on the hydraulic manifold thus allowing air pressure to move the pilot control valve to the ‘close’ position. The solenoid valve on the right in the diagram vents the other side of the air cylinder. With the pilot control valve in the ‘close’ position, pilot fluid at 3000 psi is sent down the umbilical to the RAMS CLOSE SPM valve in the subsea control pods. The pressure lifts the spindle in this valve so that it seals against: the upper seat, thus blocking the vent . At the same time power fluid at its regulated pressure is allowed past the bottom of the spindle and into the valve block in the male and female sections of the control pod. From the bottom of the female section, the power fluid then travels through the shuttle valve to the ‘close’ side of the BOP ram cylinder. Simultaneous reciprocal action in the RAMS OPEN SPM valve vents the hydraulic fluid from the ‘open’ side of the BOP ram.

9-6

V4 Rev March 2002


Figure 9.3 OPERATING SEQUENCE - GENERAL V4 Rev March 2002

9-7


CONTROL PANEL

CLOSE

BLOCK

OPEN

SOLENOID VALVE

PILOT FLUID ACCUMULATORS

POWER FLUID ACCUMULATORS

SOLENOID VALVE

MIX WATER TANK PILOT CONTROL VALVE

AIR OPERATOR POD SELECT VALVE

RIG AIR

REGULATOR

YELLOW POD

CLOSE SPM

BLUE POD

OPEN SPM

INACTIVE POD

SHUTTLE VALVE

SHUTTLE VALVE

BOP RAMS

KEY PILOT psi ACCUMULAT OR psi REGULATOR psi VENT psi

Figure 9.3.A OPERATING SEQUENCE - CLOSE FUNCTION 9-8

V4 Rev March 2002


CONTROL PANEL

CLOSE

BLOCK

OPEN

SOLENOID VALVE



SOLENOID VALVE



RIG AIR

YELLOW POD

REGULATOR

BLUE POD

CLOSE SPM

OPEN SPM

INACTIVE POD

SHUTTLE VALVE

SHUTTLE VALVE

BOP RAMS


Figure 9.3.B OPERATING SEQUENCE - BLOCK V4 Rev March 2002

9-9


CONTROL PANEL

CLOSE

BLOCK

OPEN

SOLENOID VALVE



SOLENOID VALVE



RIG AIR

REGULATOR

YELLOW POD

CLOSE SPM

BLUE POD

OPEN SPM

INACTIVE POD

SHUTTLE VALVE

SHUTTLE VALVE

BOP RAMS


Figure 9.3.C OPERATING SEQUENCE - OPEN FUNCTION

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V4 Rev March 2002


BLOCK FUNCTION The block function is used to vent a pilot control valve. By doing this individually on each valve a leak in the control system or the preventers can be located and isolated. By centring and venting all the valves when the accumulator unit is first being pressurised unintentional and inadvertent operation of the various other positions and functions can be eliminated. Referring to Fig 9.3b, when the ‘block’ button is pressed, both the solenoid valves are actuated in such a way as to apply pressure to both sides of the air operator. This causes the pilot control valve to be centred which then allows both the pilot ‘open’ and ‘close’ lines to be vented. The springs in both the SPM valves then push the spindles down so that they seal against the bottom seats and block the flow of any power fluid through the valves. At the same time this also vents both sides of the BOP ram operating cylinders. OPEN FUNCTION This sequence is the parallel opposite of the CLOSE function. As shown in Fig 9.3c, when the ‘open’ button is pressed, the solenoid valves on the hydraulic control manifold are actuated and allow air pressure to move the operator on the pilot control valve to the ‘open’ position. The solenoid valve on the left in the diagram vents the ‘close’ side of the operating piston. The pilot fluid can then flow down to the subsea control pod where it lifts the spindle in the RAMS OPEN SPM valve thus blocking the vent and allowing power fluid to flow through the valve. From the pod the power fluid travels through the ‘open’ shuttle valve to the ‘open’ sides of the BOP ram operating cylinders. Simultaneous reciprocal action in the RAMS CLOSE SPM valve allows the fluid from the ‘close’ side of the operating cylinders to be vented. CONTROL FLUID CIRCUIT In addition to the control fluid circuits used to operate stack functions such as ram or annular preventers, the control system must also perform other functions such as control of subsea regulators, provide readback pressures, latch/unlatch the subsea control pods and charge the subsea accumulators. Fig 9.4 shows a typical control fluid circuit. The hydraulic fluid is mixed, pressurised and stored in accumulator bottles by the hydraulic power unit. A pilot operated accumulator isolator valve is provided to allow the pumps to charge the subsea accumulators. When control fluid is used, it passes through a totalising flow meter in the hydraulic control manifold and then through the pod selector valve which directs it to the chosen subsea pod. After passing through the jumper hose and the subsea hose bundle to the control pod, the fluid supplies the hydraulically operated subsea regulators. These reduce the fluids pressure to that required to operate the particular BOP function desired. The fluid is also routed to a SPM valve in the pod which is controlled by the accumulator isolator valve on the hydraulic control manifold. In the open position this SPM valve allows the control fluid to charge the stack mounted accumulator bottles. Shuttle valves allow the bottles to be charged from either pod. V4 Rev March 2002

9 - 11


WATER SUPPLY

FLUID MIXING SYSTEM

ACCUMULATOR UNIT ACCUMULATOR PRECHARGED TO 1000 PSI

WATER SOLUBLE CONCENTRATE

MIXED FLUID RESERVOIR

ACCUMULATOR ISOLATOR VALVE

PRESSURE SWITCH SET AT 3000 PSI

M ACCUMULATOR ISOLATOR VALVE (PILOT)

TRIPLEX PUMP

FLOW METER

POD SELECTOR VALVE

PILOT SUPPLY

HYDRAULIC MANIFOLD

QUICK DISCONNECT JUNCTION BOX BLUE

YELLOW

TO YELLOW HOSE REEL

QUICK DISCONNECT JUNCTION BOX

BLUE POD

POD MOUNTED ACCUMULATOR ISOLATOR VALVE

BLUE HOSE REEE

HYDRAULIC REGULATORS CONTROL FLUID TO SPM VALVES

FROM YELLOW POD 1/4" SHUTTLE VALVE

FROM YELLOW POD 1 1/4" SHUTTLE VALVE

STACK MOUNTED ACCUMULATOR ISOLATOR VALVE

STACK MOUNTED ACCUMULATOR

Figure 9.4 SUBSEA CONTROL SYSTEM - HYDRAULIC SCHEMATIC

9 - 12

V4 Rev March 2002


PILOT FLUID CIRCUIT The pilot valves in the subsea pods are controlled from the surface by means of control valves located in the hydraulic control manifold. These control valves can be operated either manually from the control manifold itself or remotely from an electrical panel via pneumatic solenoid valves. Any BOP stack function such as a failsafe valve, which requires pressure only to open or close it is called a 2-position function. There is an ‘operate’ position and a ‘vent’ position. The latter position is used to release pressure from the operating side of the pilot valve. Fig 9.5 shows a typical 2-position function pilot circuit. The control valve, a 1/4', four-way manipulator valve, can be controlled from a remote panel via the two solenoid valves which can place the valve either in the ‘open’ or ‘vent’ positions. A pressure switch connected to the discharge line of the control valve is activated when a pilot signal is present and lights up the appropriate lamp on the control panel. In the ‘open’ position the pilot signal is transmitted to the subsea control pods where it operates its associated pilot valve which then allows the power fluid to flow through the selected pod to the BOP function. A BOP stack function requiring pressure to both open and close is called a 3position function. The hydraulic pilot fluid circuit for a 3-position function is shown in Fig 9.6. It requires the use of three solenoid valves, the ‘block’ solenoid valve being used in conjunction with two shuttle valves in order to centre the control valve. A pressure switch is connected to each discharge line of the control valve and will transmit a signal to the appropriate control panel lamp whenever a pilot signal is present. The operation of the 3-position pilot circuit is as described above. The main components of the control system and some of the other operating sequences are now described in more detail.

V4 Rev March 2002

9 - 13


Solenoid Hydraulic Pilot Supply Air Supply

Open

Vent Vent

1/4" Manipulator Valve Or Selector Valve With 2 Position Air cylinder Pressure Switch Quick Disconnect Junction Box Blue

Quick Disconnect Junction Box

Quick Disconnect Junction Box

Hydraulic Manifold

Yellow

To Yellow Hose Reel

Blue Hose Reel

Blue Pod Hydraulic Regulator

SPM Valve

Control Fluid Supply

Shuttle Valve From Yellow Pod

Open Failsafe Valve Operator Showing Spring Housing And Gate

Figure 9.5 PILOT FLUID CIRCUIT (2-POSITION FUNCTION)

9 - 14

V4 Rev March 2002


Air Supply

Solenoid

Hydraulic Pilot Supply 1/4" Air Shuttle Valve

Open

Block 1/4" Manipulator Valve

Close

Pressure Switch

Vent BLUE

Quick Disconnect Junction Boo

YELLOW

NOTE: - Three Solenoid Valves Can Be Used For Critical Functions, Such As Shear Rams

To Yellow Hose Reel

Blue Hose Reel Quick Disconnect Junction Box

Control Fluid Supply SPM Valve

Blue Pod

From Yellow Pod

Shuttle Valve From Yellow Pod Close Open

Ram Type BOP

Figure 9.6 PILOT FLUID CIRCUIT (3-POSITION FUNCTION)

V4 Rev March 2002

9 - 15


9.13 HYDRAULIC POWER UNIT This unit contains the mixing system, high pressure pumps and accumulator banks as shown in Fig 9.4. MIXING SYSTEM The hydraulic power unit supplies hydraulic fluid to the entire control system. It requires fresh water, soluble oil, glycol (for freeze protection), compressed air and electrical power for operation. Two small reservoirs contain the soluble oil and glycol which are automatically blended with fresh water to make up the hydraulic fluid which is then stored in a large reservoir known as the mixed fluid tank. Since the control system is an ‘open’ one in that the used hydraulic power fluid is vented into the sea, the type of soluble oil used must be completely biodegradable. Additives to prevent bacteria growth and to inhibit corrosion are also frequently included in the mix water. The soluble oil reservoir has a capacity of at least 110 gal whilst the mix fluid tank should be capable of holding sufficient fluid to charge the system accumulators from their pre-charge condition to their maximum operating pressure. All the tanks are fitted with sight glasses and a low-level alarm system which activates a warning light and horn on the control panels. The proper mixing fluid ratio is maintained by air operated hydraulic pumps, a water pressure regulator, a double acting motor valve and a water flow rate indicator. A reservoir float switch is used to control operation of the mixing system in order to maintain the correct level of fluid and to ensure a continued supply for the control system. Water/additive concentrations can be adjusted by setting the mixing pump to run at the appropriate rate. A minimum rig water supply pressure of 25 psi is typically required for the correct operation of the mixing system and to provide a fluid supply at least equal to the rate at which mix fluid is drawn from the tank by the high pressure pumps. HIGH PRESSURE PUMPS These are the pumps which take the fluid from the mix tank and transfer it to the accumulator bottles, under pressure, where it is stored ready for use by the system. Typically, three air powered and two electrically powered pumps are used. During normal operation the electric pumps are used to recharge the system. However if these cannot keep up with demand, or fail in some way, then the air powered pumps can assist or take over completely. The electric pump assemblies consist of a heavy duty triplex reciprocating plunger pump with a chain and sprocket drive and powered by an explosion-proof motor. Pump capacity should be such that they can charge the system accumulators from their pre-charge condition to their maximum operating pressure in less than 15 minutes. See Section 9.1.4 below for calculations involving accumulator and charging pump capacities. 9 - 16

V4 Rev March 2002


SELECT 'BLOCK'

SELECT 'CLOSE'

SELECT 'OPEN'

PILOT PRESSURE

PILOT PRESSURE From 'OPEN' SPM

From 'CLOSE' SPM

Both Lines Vented

From 'OPEN' SPM

To 'CLOSE' SPM

To 'OPEN' SPM

From 'CLOSE' SPM

Vent

Vent

PV

A) SUBSEA MANIPULATOR VALVE AB

SELECT 'BLOCK'

Power Fluid Blocked

SELECT 'CLOSE'

SELECT 'OPEN'

Power Fluid

Power Fluid

From Open

From Close

To Close Side

From Open Side

Both Lines Blocked

To Open Side

From Close Side

Vent

Vent to Mix Tank

PV

B) SURFACE SELECTOR VALVE AB

Figure 9.9 ROTARY SHEAR SEAL TYPE VALVES V4 Rev March 2002

9 - 17


SUPPLY FROM POWER UNIT

PILOT ACCUMULATORS

TYPICAL PILOT CONTROL VALVE

VENT TO MIX FLUID TANK

MANUAL CONTROL HANDLE

PRESSURE SWITCH

AIR OPERATOR

PRESSURE SWITCH

'OPEN' PILOT LINE

'CLOSE' PILOT LINE JUMPER HOSES

FIGURE 9.10 PILOT CIRCUIT REGULATOR CONTROL Since the power fluid arrives at the subsea control pod at 3000 psi and the BOP functions have a maximum normal operating pressure of 1500 psi, regulators are needed in the pods - one is provided for the annular preventers and one for the ram preventers. Fig 9.11 shows how the subsea regulator is controlled from the surface. A 1/2" air operated pilot regulator in the control manifold transmits pilot pressure to the subsea regulator in order to adjust its setting. The air operator can be manipulated either manually using an air regulator on the control manifold or remotely from another control panel. When operated from a remote panel a solenoid valve is used to increase the air pressure by allowing rig air to flow into a 1 gallon receiver connected to the air pilot line. The receiver acts as a surge protector for the pilot regulator. Decreasing the air pressure is achieved by using a solenoid valve to vent the line to atmosphere. PRESSURE READBACK In order to ensure that the subsea regulator has set the desired operating pressure the manifold incorporates a readback system. The output of each subsea regulator is connected through a 1/8" hose in the umbilical back to a pressure gauge in the control manifold. Pressure transducers transmit the readback pressures to remote panels. A shuttle valve also in the manifold unit connects the lines from both umbilicals and isolates the active and inactive pods. All the electrical components are housed in separate explosion proof housings on the control manifold unit. One housing contains the solenoid valves and another contains the transducers and pressure switches. The pressure switches are typically set to be activated ‘on’ when pressure in the pilot line to the ram or failsafe SPM reaches 1000 psi and to switch ‘off, when the pressure falls to below 700 psi. 9 - 18

V4 Rev March 2002


REGULATOR PRESSURE READBACK

DECREASE

REMOTE PANEL

INCREASE

REGULATOR PRESSURE

VENT

DECREASE SOLENOID

INCREASE SOLENOID

AIR SUPPLY

AIR SUPPLY

1 GALLON AIR RECEIVER

REGULATOR PRESSURE READBACK

PILOT SUPPLY

REGULATOR PRESSURE

1/2" AIR PILOT REGULATOR PRESSURE TRANSDUCER

HYDRAULIC CONTROL MANIFOLD

PRESSURE TRANSDUCER QUICK DISCONNECT JUNCTION BOXES YELLOW

BLUE

TO YELLOW HOSE REEL

BLUE HOSE REEL QUICK DISCONNECT JUNCTION BOX

BLUE POD

REGULATED FLUID SUPPLY TO SPM VALVES

HYDRAULIC REGULATOR POWER FLUID SUPPLY

Figure 9.11 SUBSEA REGULATOR CONTROL CIRCUIT V4 Rev March 2002

9 - 19


9.1.6 CONTROL PANELS These panels permit the operation of the manifold unit from remote locations. Usually two remote panels are used - a master one on the drill floor, and a minipanel in a relatively safe location such as a rig office. Other mini-panels can be integrated into the system if desired. The drillers master panel is normally explosion proofed or air-purged since it is located in a hazardous area. It contains a set of graphically arranged push-button/ indicating lights for operation and status indication of each stack function. The regulator pressures are controlled by increase/decrease push-buttons and there are gauges for monitoring pilot and readback values. A digital readout of the flow meter located on the control manifold is also provided. Many types of drillers panel also include controls for the operation of the rig diverter system which is controlled in a similar way to a surface BOP system. The mini-panel is usually not required to be explosion proof. It operates in the same way as the master panel but does not include the pressure gauges. Both panels include ‘lamp test’ facilities to check for burnt out lamps. They also contain alarms for low hydraulic fluid level, low accumulator pressure, low rig air pressure and an alarm to indicate that the emergency battery pack is in use. The remote panels contain all the necessary electrical switches to operate the solenoid valves on the hydraulic control manifold which in turn control the air operators of the pilot control valves. Lights on the panels (red, amber, green) indicate the position of the 3-way valve (open, block, close) and there is a memory system so that when a function is in block with the amber light on, the actual position of the function (the red or green light) will also be displayed. Fig 9.12 shows in more detail the operation of a BOP function from a remote panel. Although the lights on the panels show the position of the BOP functions, the control buttons are not active until a ‘push and hold’ button is depressed in order to allow the supply of electrical power to the panel. The sequence of events that occur is as follows -

9 - 20

V4 Rev March 2002


CLOSE 1.

The ‘press and hold’ button is held in to activate the panel.

2.

The ‘close’ button is pressed.

3.

Current flows to the ‘close ‘ solenoid valve which lifts to supply air to the 3-position air operator.

4.

The air operated piston moves the pilot control valve to the ‘closes position and pilot pressure is sent to the subsea control pod.

5.

Successful pressurisation of the pilot line to the control pod actuates a pressure switch on the control manifold.

6.

Current flows through an electronic card which illuminates the lamp of the ‘close’ button indicating that the function is now closed.

7.

The ‘press and hold’ button is released, the ‘close’ lamp remains illuminated.

'PUSH AND HOLD' BUTTON

CONTROL PANEL CLOSE

BLOCK

OPEN


ELECTRIC SUPPLY ELECTRONIC CARD

SOLENOID VALVE

SOLENOID VALVE

AIR OPERATOR

RIG AIR

MIX WATER TANK

PILOT CONTROL VALVE

'CLOSE' PRESSURE SWITCH

'OPEN' PRESSURE SWITCH PILOT LINES TO SUBSEA PODS KEY PILOT psi ACCUMULAT OR psi REGULATOR psi VENT psi

Figure 9.12A REMOTE OPERATION -CLOSE FUNCTION

V4 Rev March 2002

9 - 21


OPEN 1.


2.

The ‘open’ button is pressed.

3.

Current flows to the ‘open ‘ solenoid valve which lifts to supply air to the 3-position air operator.

4.

The air operated piston moves the pilot control valve to the ‘open’ position and pilot pressure is sent to the subsea control pod.

5.

Successful pressurisation of the pilot line to the control pod actuates a pressure switch on the control manifold.

6.

Current flows through an electronic card which illuminates the lamp of the 'open’ button and extinguishes the ‘close’ lamp indicating that the function is now open.

7.

The ‘press and hold’ button is released, the ‘open’ lamp remains illuminated. 'PUSH AND HOLD' BUTTON

CONTROL PANEL CLOSE

BLOCK

OPEN



SOLENOID VALVE

SOLENOID VALVE

AIR OPERATOR

RIG AIR

MIX WATER TANK

PILOT CONTROL VALVE



Figure 9.12B REMOTE OPERATION - OPEN FUNCTION

9 - 22

V4 Rev March 2002


BLOCK 1.


2.

The ‘block’ button is pressed.

3.

Current flows to both the ‘close ‘ and ‘open’ solenoid valves which lift to supply air to both sides of the 3-position air operator piston.

4.

The air operated piston moves to a central position which places the pilot control valve in the middle ‘block’ position so that no pilot pressure is sent down either the ‘close’ or ‘open’ pilot line.

5.

Since no pilot line is pressurised, neither pressure switch is activated.

6.

The electronic card senses that no pressure switch has been operated and illuminates the ‘block’ lamp.

7.

The ‘press and hold’ button is released, the ‘block’ lamp remains illuminated.

'PUSH AND HOLD' BUTTON

CONTROL PANEL CLOSE

BLOCK

OPEN



SOLENOID VALVE

SOLENOID VALVE

AIR OPERATOR

RIG AIR

MIX WATER TANK

PILOT CONTROL VALVE



Figure 9.12C REMOTE OPERATION - BLOCK FUNCTION

V4 Rev March 2002

9 - 23


The ‘block’ position is of use to try and locate the position of a hydraulic leak in the system by systematically isolating the various BOP stack functions. It is also used to depressurise the pilot lines when attaching junction boxes to the umbilical hose reels. Note that the illumination of a push button lamp only indicates that a pilot pressure signal has been generated and not that a function has been successfully operated subsea. Indications of a successful subsea function movement are a. The flow meter shows that the correct amount of power fluid has been used. b. There are fluctuations in manifold and readback pressure readings. c. There is a noticeable drop in accumulator pressure. The BOP functions can be controlled from any panel at any time during normal operations. If one panel or a cable to a panel is damaged, destroyed or malfunctions then it will not interfere with the operation of the system from any other panel. An emergency battery pack supplies the electric panels with power for a period of up to 24 hours (depending on use) in case of failure of the rig supply. The power pack typically consists of ten 12 volt lead-acid batteries. A battery charger is also included to maintain the batteries in a fully charged condition ready for immediate use. Electrical cable connects the remote panels and the battery pack to the junction boxes on the hydraulic control manifold. 9.1.7 HOSE REELS The hose bundles are mounted on heavy duty reels for storage and handling and are connected to the hydraulic control manifold by jumper hoses. The reels are driven by reversible air motors and include a disc brake system to stop the reel in forward or reverse rotation. When the subsea control pod is run or retrieved, the junction box for the jumper hose is disconnected from the hose reel. However in order to keep selected functions ‘live’ during running or retrieval operations, five or six control stations are mounted on the side of the reel. These live functions include at least the riser and stack connectors, two pipe rams and the pod latch. Fig 9.13 is a schematic of the hydraulic system through which the power fluid flows to the controlled functions during reel rotation. Once the BOP has been landed and latched on to the wellhead, the control points on the side of the reel are shut down and isolated to prevent interference with the full control system. The regulators on the reel which control the manifold and annular pressures must also be isolated in case they dump pressure when the jumper hose RBQ plate is attached. With the supply pressure isolated the 3-position, 4-way valves are used to vent any pressure that may remain trapped in a pilot line holding an SPM valve open. This is necessary since the reel is fitted with a different type of valve to the control manifold manipulator valves. These valves look similar but do not vent when placed in the ‘block’ position (see Fig 9.12b). 9 - 24

V4 Rev March 2002


MANIFOLD REGULATOR

MAIN HYDRAULIC SUPPLY THROUGH SWIVEL JOINT 1/4" SELECTOR VALVES

JUMPER HOSE FROM HYDRAULIC MANIFOLD

BLUE POD HOSE REEL VALVE MANIFOLD MOUNTED ON SIDE OF HOSE REEL HOSE BUNDLE

BLUE POD JUNCTION BOX

OPEN SPM SHUTTLE VALVE

REGULATOR OPEN CLOSE SPM

BLUE POD

FROM YELLOW POD

SHUTTLE VALVE

CLOSE

Figure 9.13 HOSE REEL CONTROL MANIFOLD

V4 Rev March 2002

9 - 25


9.1.8 UMBILICAL HOSE The umbilical transmits all power fluid and all pilot signals from the surface to the subsea control pods. Hydraulic pressure from the regulated side of the subsea regulators is also transmitted through the umbilical to pressure readback gauges at surface. The power fluid is supplied only to the umbilical of the selected active pod, whereas pilot pressure is normally supplied to both the active and inactive pods. The most common umbilicals contain a 1" ID supply hose for the power fluid which is surrounded by up to sixty four 1/8" and 3/16" hoses for pilot valve activation and readbacks. An outer polyurethane covering protects the whole bundle. Roller sheaves are used to support the umbilical and provide smooth and safe handling where it leaves the hose reel and goes over the moon pool area. Special clamps are used to attach the hose bundle to the pod wireline at intervals that correspond to the lengths of riser in use. 9.1.9 SUBSEA CONTROL PODS The subsea control pods contain the equipment that provides the actual fluid transfer from the hose bundle to the subsea stack. A typical pod assembly (Fig 9.14) consists of three sections • a retrievable valve block • an upper female receptacle block permanently attached to the lower marine riser package • a lower female receptacle permanently attached to the BOP stack Control fluid enters the pod at the junction box and is routed either direct to an SPM valve or to one of the two regulators (one for the BOP rams and one for the annular preventers) from where it is sent to the appropriate SPM. When a SPM pilot valve is actuated it allows the control fluid to pass through it to one of the exit ports on the lower part of the male stab and into the upper female receptacle attached to the lower marine riser package. For those functions which are part of the lower marine riser package the fluid is then routed out of the upper female receptacle and directed via a shuttle valve to the functions operating piston. For those functions which are part of the main BOP stack, the fluid is routed through the upper female receptacle and into the lower female receptacle from where it goes via a shuttle valve to the appropriate operating piston. Not all the functions on the BOP stack are controlled through pod mounted pilot valves. Low volume functions such as ball joint pressure are actuated directly from surface through 1/4" lines. These are generally referred to as straight through functions.

9 - 26

V4 Rev March 2002


Figure 9.14 KOOMEY

V4 Rev March 2002

9 - 27


The integrity of each fluid route between the different sections is achieved by using a compression seal that is installed in the retrievable valve block section of the pod. Compression between the three sections is achieved by hydraulically locking the pod into the lower receptacle (which is spring mounted on the BOP stack in order to facilitate easier engagement). Locking is accomplished by hydraulically extending two dogs that locate under the bottom of the upper female receptacle. A helical groove on the outside of the lower skirt of the pod ensures correct alignment of the fluid ports. To retrieve the pod independently of the lower marine riser package, the locking pressure is bled off and the dogs are retracted mechanically when an overpull is taken on the retrieving wire. A more recent design utilises the same concept but consists of a cube shaped retrievable valve block which latches over two tapered blocks mounted on a base plate permanently attached to the lower marine riser package. A single tapered block mounted on a spring base is permanently attached to the BOP stack. The packer seals on the retrievable valve block are pressure balanced in a breakaway condition so that there is no tendency for it to be blown out of the pocket if the pod has to be released under pressure. Besides the latching system, packer seals and piping, the principal components of the retrievable valve blocks are the SPM pilot valves and regulators. SPM VALVES As described above these valves direct the regulated power fluid to the desired side of the preventer, valve or connector operating piston and vent the fluid from the other side of the piston to the sea. The annular preventers typically use large 1 1/2" SPM valves in order to provide sufficient fluid flow, the ram preventers use 1" valves and the other functions such as failsafe valves and connectors use 3/4" valves. Fig 9.15 shows a NL Shaffer 1 in SPM valve. The valve is a poppet type in which a sliding piston seals at the top and bottom of its travel on nylon seats. In the normally closed position a spring attached to the top of the piston shaft keeps the piston on the bottom seat and prevents the power fluid from passing through the valve to the exit port. Power fluid pressure, which is permanently present, also assists in keeping the valve closed by acting on a small piston area on the spindle. In this position fluid from the valve’s associated operating piston is vented through the sliding piston at ambient conditions. When pilot pressure is applied to the valve the sliding piston moves up and seals against the upper seat which blocks the vent ports and allows regulated power fluid to flow through the bottom section of the valve to function the BOP. Note that the pilot fluid therefore operates in a closed system whilst the hydraulic power or control fluid is an ‘open’ circuit with all used fluid being vented to the sea. As illustrated in Fig 9.3 two SPM pilot valves are required to operate a BOP function. 9 - 28

V4 Rev March 2002


Compressed Spring S.P.M. "ACTIVATED"

Sea Water Hydrostatic Upper Seat

Pilot Pressure In 3000 PSI

Power Fluid Vent

Lower Seat

Power Regulated Fluid In

Power Fluid Out

Figure 9.15 NL SHAFFER 1" SPM VALVE REGULATORS Each subsea control pod contains two regulators - one to regulate pressure for the ram preventers and one to regulate the pressure for operating the annular preventers. Some control systems incorporate a third regulator so that the operating pressure of each annular preventer can be individually manipulated. Typical regulators are 1 l/2" hydraulically operated, stainless steel, regulating and reducing valves. As shown in Fig 9.11 the output line of each regulator is tapped and the pressure roused back to a surface gauge through the umbilical. This readback pressure is used to confirm that the subsea regulator is supplying the power fluid at the pressure set by the pilot surface regulator. 9.1.10 REDUNDANCY The two subsea control pods are functionally identical. When a pilot control valve (rams close for example) is operated on the hydraulic control manifold a pilot signal is sent down both umbilicals so that the associated SPM valve in each pod ‘fires’. If the pod selector valve is set on yellow then power fluid is sent only to this pod and it is only through the SPM valve in this pod that the fluid will reach the ram operating piston. The pod selection has no effect on the pilot system. Once the yellow pod SPM valve ‘fires’, the power fluid passes through it to a shuttle valve, the shuttle piston of which moves across and seals against the blue pod inlet. The fluid then passes through the shuttle valve to move the ram to the close position. Fluid from the opposite side of the operating piston is forced out through the ‘ram open’ shuttle valve and vented through the ‘ram open’ SPM valve and into the sea. V4 Rev March 2002

9 - 29


Note that if the blue pod was now selected to open the rams; then the power fluid would flow to the ram through the ‘open’ SPM on the blue pod but the fluid from the ‘close’ side of the piston would be vented through the yellow pod SPM since the ‘close’ shuttle piston would still be sealing the blue pod inlet port. The shuttle valves should be located as near as possible to their relevant ports on the BOP stack since the system is redundant only down as far as the shuttle valves. Fig 9.16 shows a NL Shaffer shuttle valve.

Figure 9.16 N LN SHAFFER SHUTTLE VALVE

9.1.11 TROUBLE SHOOTING Trying to locate a fluid leak or a malfunction of the subsea control system requires a very thorough knowledge of the equipment and a systematic approach to tracing the source of the problem. Subsea control systems are very complex in their detail and there are always minor variations and modifications even between similar models therefore trouble shooting should always be carried out with reference to the relevant schematics. LEAKS A fluid leak is usually detected by watching the flow meter. If a flow is indicated when no function is being operated or if the flow meter continues to run and does not stop after a function has been operated then a leak in the system is implied. 9 - 30

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Once it has been determined that there is a leak then the following steps could be used to try and locate its source CHECK THE SURFACE EQUIPMENT • examine the hydraulic control manifold for a broken line or fitting • examine the accumulator bottles for signs of a fluid leak • check the jumper hoses for signs of damage • check the hose reels and junction boxes for loose connections • examine the hose reel manifold to ensure that all the valves are centred make certain that the shut-off valve to the reel manifold pressure supply is tightly closed (if this is left open when the junction box is connected to the reel, it will allow fluid pressure to be forced back through one of the surface regulators and vent into the mix water tank thus indicating a leak) If this fails to locate the source of the leak then return to the hydraulic control manifold for an item-by-item check of the system USE THE POD SELECTOR VALVE TO OPERATE THE SYSTEM ON THE OTHER POD • If the leak does not stop then it must be located either in the hydraulic control manifold or downstream of the subsea control pods • if the leak does stop then it will be known which side of the system it is in Further checks would then be as follows If the Leak Stops • assuming conditions permit, switch back to the original pod and block each function in turn (allow plenty of time for the function to operate and check the flowmeter on each operation) • if the leak stops when a particular function is set to block then the leak has been isolated and it is somewhere in that specific function • in this case run the subsea TV to observe the pod whilst unblocking the function • if the leak is coming from the pod it will be seen as a white mist in the water and a bad SPM valve or regulator can be assumed and the options are •pull the pod to repair the faulty component • leave the function in block until the stack or lower marine riser package is retrieved V4 Rev March 2002

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• If the leak is seen to be coming from below the pod then the options are • attempt repairs using divers • leave the function in block until the stack is brought to surface If the Leak Does Not Stop • check the return line to the mix water tank (if there is fluid flowing from this line then there is a leaking control valve or regulator) • check that all the control valves are in either the open closed or block position (a partially open valve can allow fluid to leak past it) • if the valve positions are correct then disconnect the discharge line from each valve - one at a time (fluid flow from a discharge line indicates a faulty valve) • if the discharge lines do not show any signs of a leak then disconnect the discharge lines from the regulators in the same way It can sometimes be the case that the system is operating normally until a particular function is operated and the flowmeter continues to run after the time normally required for that function to operate. In this case there is a leak in that function with a likely reason being foreign material in the SPM valve not allowing the seat to seal thus causing the system to leak hydraulic fluid. A possible remedy is to operate the valve several times to try and wash out the foreign material. Observe the flowmeter to see if the leak stops. If the leak still persists then it will be a case of running the subsea TV to try and locate the leak visually.

MALFUNCTIONS Typical control system malfunctions are slow reaction times or no flowmeter indication when a button is pressed to operate a function. A slow reaction time could be due to • low accumulator pressure • a bad connection between the jumper hose and hose reel • a partially plugged pilot line In this case the trouble shooting sequence would be -

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CHECK THE PRESSURES • verify that the gauges are indicating the correct operating pressures • if a low pressure is indicated then verify correct operation of the high pressure pumps and check the level of hydraulic fluid in the mix water tank • check that the shut-off valve between the accumulators and the hydraulic control manifold is fully open CHECK THE HOSES • if the pressures are good then check all the surface hose connections • check the junction box connections (if they are not tightly seated, the flow rate through the connection can be restricted and cause the function to operate slowly) CHECK THE PILOT LINES • if the above checks fail to locate the problem then the final option will be to retrieve the pod and check the pilot line for any sludge that may have settled out from the hydraulic fluid (disconnect each pilot line from the pod one at a time and flush clean fluid through it In the situation where there is no flowmeter indication when a function button is pressed, this could be due to no accumulator or pilot pressure • the control valve on the hydraulic manifold did not shift • the flowmeter is not working properly • there is a plugged pilot line or a faulty SPM valve CHECK THE PRESSURES • verify that the gauges are indicating the correct operating pressures • if a low pressure is indicated then verify correct operation of the high pressure pumps and check the level of hydraulic fluid in the mix water tank • check for correct operation of the pressure switches • check the fluid filters to make certain they are not plugged • check the accumulator pre-charge pressures V4 Rev March 2002

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• bleed the fluid from the bottles back into the tank and check the nitrogen pressure in each bottle CHECK THE HYDRAULIC CONTROL MANIFOLD • use the ‘test’ button on the control panel to make certain that the position lamps are not burnt out check the air and electrical supply to the hydraulic control manifold • check the electrical circuits to the control panel and also the solenoid valves and power relays • if the air supply pressure is sufficient to work the control valve operator check for an obstruction to the manual control handle • if the valve can be easily operated manually then replace the entire valve assembly with a valve known to be in good working order CHECK THE FLOWMETER • if the regulator pressure drops by 300 to 500 psi when the function is operated and then returns to normal, the function is probably working correctly and the flowmeter is faulty • monitor the flowmeter on the hydraulic manifold to verify that the one on the drillers panel is not at fault (the impulse unit that sends the flowmeter signal to the panel could malfunction)

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SECTION 9.2 MARINE RISER SYSTEMS GENERAL 9.2.1 A marine riser system is used to provide a return fluid flow path from the wellbore to either a floating drilling vessel (semi submersible or hull type) or a bottom supported unit, and to guide the drill string and tools to the wellhead on the ocean floor. Components of this system include remotely operated connectors, flexible joints (balljoints), riser sections, telescopic joints, and tensioners. Data on these components, together with information on care and handling of the riser, are included in this Section, API RP 2K: Recommended Practice for Care and Use of Marine Drilling Risers* and API RP 2Q: Recommended Practice for design and Operation of Marine Drilling Riser Systems.* 9.2.2 For a drilling vessel, the marine riser system should have adequate strength to withstand: a.

dynamic loads while running and pulling the blowout preventer stack;

b.

lateral forces from currents and acceptable vessel displacement;

c.

cyclic forces from waves and vessel movement;

d.

axial loads from the riser weight, drilling fluid weight, and any free standing pipe within the riser; and

e.

axial tension from the riser tensioning system at the surface (which may be somewhat cyclic) or from buoyancy modules attached to the exterior of the riser.

Unless otherwise noted, internal pressure rating of the marine riser system (pipe, connectors, and flexible joint) should be at least equal to the working pressure of the diverter system plus the maximum difference in hydrostatic pressures of the drilling fluid and sea water at the ocean floor. In deeper waters, riser collapse resistance, in addition to internal pressure rating, may be a consideration if circulation is lost or the riser is disconnected while full of drilling fluid. 9.2.3 For bottom-supported units, consideration should be given to similar forces and loads with the exception of vessel displacement, vessel movement, and high axial loads. Operating water depths for bottom-supported units are often shallow enough to permit free standing risers to be used without exceeding critical buckling limits, with only lateral support at the surface and minimal tension being required to provide a satisfactory installation.

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9.2.4 Information presented in this Section applies primarily to floating drilling vessels, since more demanding conditions normally exist for these marine riser systems than for those installed for bottom-supported units. *Available form American Petroleum Institute, Production Department, 2535 One Main Place, Dallas TX 75202-3904

MARINE RISER SYSTEM COMPONENTS (NOTE: Additional details are contained in API RP 2K: Recommended Practice for Care and Use of Marine Drilling Risers and API RP 2Q: Recommended Practice for Design and Operation of Marine Drilling Riser Systems.)

Remotely Operated Connector 9.2.5 A remotely operated connector (hydraulically actuated) connects the riser pipe to the blowout preventer stack and can also be used as an emergency disconnect from the preventer stack, should conditions warrant. Connector internal diameter should be at least equal to the internal bore of the blowout preventer stack. Its pressure rating can be equal to either the other components of the riser system (connectors, flexible joint, etc.) or to the rated working pressure of the blowout preventer stack (in case special conditions require subsequent installation of additional preventers on top of the original preventer stack). Connectors with the lower pressure rating are designated CL while those rated at the preventer stack working pressure are designated C . Additional factors to be H considered in selection of the proper connector should include ease and reliability of engagement/disengagement, angular misalignments, and mechanical strength. 9.2.6 Engagement or disengagement of connector with the mating hub should be an operation that can be repeatedly accomplished with ease, even for those conditions here some degree of misalignment exists. 9.2.7 Mechanical strength of connector should be sufficient to safely resist loads that might reasonably be anticipated during operations. This would include tension and compression loads during installation, and tension and bending forces during both normal operations and possible emergency situations. Marine Riser Flexible Joint (Ball Joint) 9.2.8 A flexible joint is used in the marine riser system to minimise bending moments, stress concentrations, and problems of misalignment engagement. The angular freedom of a flexible joint is normally 10 degrees from vertical. A flexible joint is always installed at the bottom of the riser system either immediately above the remotely operated connector normally used for connecting/disconnecting the riser from the blowout preventer stack, or above the annular preventer when the annular preventer is placed above the remotely operated connector.

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9.2.9 For those vessels having a diverter system, a second flexible joint is sometimes installed between the telescopic joint and the diverter to obtain required flexibility, or some type of gimbal arrangement may also be used. For deep water operations or unusually severe sea conditions, another flexible joint may be installed immediately below the telescopic joint. 9.2.10 Mechanical strength requirements for flexible joints are similar to those for the remotely operated connector. They should be capable of safely withstanding loads that might reasonably be encountered during operations, both normal and emergency. In addition, the angular freedom of up to approximately 10 degrees should be accomplished with minimum resistance while the joint is under full anticipated load. Hydraulic “pressure balancing” is recommended for ball-type flexible joints to counteract unbalanced forces of tensile load, drilling fluid density, and sea water density. This pressure balancing also provides lubrication for flexible joints. 9.2.11 Technical investigations and experience have shown the importance of close monitoring of the flexible joint angle during operations to keep it at a minimum. One method of accomplishing this is by the use of an angle-azimuth indicator. The flexible joint angle, vessel offset, and applied (riser) tension are indications of stress levels in the riser section. For continuous drilling operations, the flexible joint should be maintained as straight as possible, normally at an angle of less than 3 degrees: greater angles cause undue wear or damage to the drill string, riser, blowout preventers, wellhead or casing. For riser survival (i.e. to prevent overstressing) the maximum angle will vary from about 5 degrees to something less than 11 degrees, depending upon parameters such as water depth, vessel offset, applied tension, and environmental conditions. Drill pipe survival must also be considered if the pipe is in use during those critical times of riser survival conditions. Marine Riser Sections (Refer to API RP 2Q: Recommended Practice for Design and Operation of Marine Drilling Riser Systems* for additional details.)

9.2.12 Specifications for riser pipe depend upon service conditions. It should be noted, however, that drilling vessels normally encounter a wide variety of environments during their service life; consequently, the riser should have a minimum yield strength and fatigue characteristics well in excess of those required not only for the present but for reasonably anticipated future conditions.

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9.2.13 Riser pipe steel should conform to ASTM Designation A-530: General Requirements for Specialised Carbon and Alloy Steel Pipe† and be fabricated and inspected in accordance with API Spec 5L: Specification for Line Pipe*. Specifications that provide riser pipe with a reasonable service life for operation in most parts of the world include a steel having a minimum yield strength of between 50,000 psi and 80,000 psi. Risers with lower minimum yield strength (35,000 psi) have proven satisfactory if used in those areas where only light to moderate service conditions are encountered. †Available from American Petroleum Institute. Production Department, 2535 One Main Place, Dallas TX 75202-3904. *Available from American Society for Testing and Materials, 1916 Race St, Philadelphia Pennsylvania 19103.

9.2.14 Computer programs are available for determining riser stresses under various operating conditions, and should be used for installations where previous experience is limited or lacking. Permissible operating stresses are normally expressed as a percent of minimum yield strength and depend upon the preciseness of the data input. For any combination of service conditions (i.e. environmental, vessel offset, drilling fluid weight riser weight, etc.). there is an optimum riser tension for which static and dynamic riser stresses are minimum. 9.2.15 The internal diameter of the riser pipe is determined by size of the blowout preventer stack and the wellhead, with adequate clearances being necessary for running drilling assemblies, casing and accessories, hangers, packoff units, wear bushings, etc. 9.2.16 Marine riser connectors should provide a joint having strength equal to or greater than that of the riser pipe. For severe service, quench and tempering and shotpeening the connector pin end are sometimes done. The joint, when made up and tested under reasonable maximum anticipated service loads, should have essentially no lateral, vertical, or rotational movement. After release of load, the, joint should be free of deformation, galling or irregularities. Make-up practice, including bolt- torque requirement, should be specified by the manufacturer. 9.2.17 Auxiliary drilling fluid circulation lines are sometimes required and included as an integral part of large diameter riser systems. Drilling fluid can be pumped into the lower section of the riser system to maintain adequate annular velocities while drilling small diameter holes. The number of lines, size, and pressure rating will be determined by flow rates and pressures required. Marine Riser Telescopic Joint 9.2.18 The telescopic joint serves as a connection between the marine riser and the drilling vessel, compensating principally for heave of the vessel. It consists of two main sections, the outer barrel (lower member) and the inner barrel (upper member).

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9.2.19 The outer barrel (lower member), connected to the riser pipe and remaining fixed with respect to the ocean floor, is attached to the riser tensioning system and also provides connections for the kill and choke lines. A pneumatically or hydraulically actuated resilient packing element contained in the upper portion of the outer barrel provides a seal around the outside diameter of the inner barrel. 9.2.20 The inner barrel (upper member), which reciprocates within the outer barrel, is connected to and moves with the drilling vessel and has an internal diameter compatible with other components of the marine riser system. The top portion of the inner barrel has either a drilling fluid return line or diverter system attached, and is connected to the underneath side of the rig sub structure. 9.2.21 The telescopic joint, either in the extended or contracted position, should be capable of supporting anticipated dynamic loads while running or pulling the blowout preventer stack and should have sufficient strength to safely resist stresses that might reasonably be anticipated during operations. Stroke length of the inner barrel should provide a margin of safety over and above the maximum established operating limits of heave for the vessel due to wave and tidal action. 9.2.22 Selection of a telescopic joint should include consideration of such factors as size and stroke length, mechanical strength, packing element life, ease of packing replacement with the telescopic joint in service, and efficiency in attachment of appurtenances (i.e. tensioner cables, choke and kill lines, diverter systems. etc.). Marine Riser Tensioning System 9.2.23 The marine riser tensioning system provides for maintaining positive tension on the marine riser to compensate for vessel movement. The system consists of the following major components: a.

tensioner cylinders and sheave assembly.

b.

hydropneumatic accumulators/air pressure vessels,

c.

control panel and manifolding,

d.

high pressure air compressor units, and

e.

stand-by air pressure vessels.

Tensioning at the top of the riser is one of the more important aspects of the riser system, as it attempts to maintain the riser profile as nearly straight as practicable and reduce stresses due to bending. As tension is increased, axial stress in the riser also increases. Therefore, an optimum tension exists for a specific set of operating conditions (water depth, current, riser weight, drilling fluid density, vessel offset, etc.).

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9.2.24 Wirelines from the multiple hydraulic tensioner cylinders are connected to the outer barrel of the telescopic joint. These cylinders are energised by high pressure air stored in the pressure vessels. Tension on the wirelines is directly proportioned to the pressure of stored air. In general, as the vessel heaves upward, fluid is forced out of the hydraulic cylinders thereby compressing air. As the vessel heaves downward pressure of the compressed air will cause the hydraulic cylinders to stroke in the opposite direction . 9.2.25 Selection of tensioners should be based on load rating, stroke length, speed of response, service life, maintenance costs, and ease of servicing. Maximum load rating of individual tensioners depends on the manufacturer, typically ranging from 45.000 to 80.000 pounds and allowing maximum vertical vessel motion of 30 to 50 feet. Design of the wireline system that supports the riser must take into consideration the angle between the wireline and the axis of the telescopic joint and its influence on stresses. 19.2.26 The number of tensioners required for a specific operation will depend on such factors as riser size and length, drilling fluid density, weight of suspended pipe inside the riser, ocean current, vessel offset, wave height and period and vessel motion. Computer programs are available for riser analysis, including tensioning requirements. Consideration should also be given to operating difficulties that might occur should one of the tensioners experience wireline failure. Recommendations for marine riser design and operation of riser tensioning systems are contained in APl RP 2K: Recommended Practice for Care and Use of Marine Drilling Risers and API RP 2Q: Recommended Practice for Design and Operation of Marine Drilling Riser Systems.* 9.2.27 Periodic examination of riser tensioning system units should be made while in service, since the system can cycle approximately 6000 times per day. Particular care should be taken to establish a wireline slipping and replacement program based on ton cycle life for the particular rig installation. Users should consult the equipment manufacturer for general maintenance procedures and specifications recommendations. Buoyancy 9.2.28 For deeper waters, it may be impractical from an operating view point to install sufficient units capable of providing adequate tensioning. In these cases, some types of riser buoyancy may be the solution (flotation jackets, buoyancy tanks, etc.) Buoyancy reduces the top tensioning requirements but loses some of its effectiveness as a result of the increased riser diameter exposing a greater cross sectional area to wave forces and ocean currents. Selection of the optimum method and/or material for obtaining buoyancy requires careful consideration of a number of factors, including water absorption, pressure integrity, maintenance requirements, abuse resistance, and manufacturer's quality control. Several of these factors are time and water-depth dependent. As water depth increases, these

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factors become more critical. A part of any analysis for an optimum safe system should include consideration of the consequences of buoyancy failure during operations. Riser Running and Handling 9.2.29 Well trained crews and close supervision are needed for maximum efficiency and to preclude any failure from improper handling or make-up of marine riser connectors. Some special equipment and tools for handling, running, and make-up/break-out may also be beneficial, both in protecting the riser and improving efficiency. These tools include a flare-end guide tube for guiding the riser through the rotary table and a joint laydown trough installed in the V-door. Care should also be taken in protecting riser joints stored on the vessel. Marine Riser Inspection and Maintenance 9.2.30 As marine riser joints are removed from service, each joint and connector should be cleaned, surfaces visually inspected for wear and damage, damaged packing or seals replaced, and surface relubricated as required. Buoyancy material and/or systems, if installed, should also receive close inspection. Prior to running a riser, thorough inspection of all components may also be warranted, particularly if the riser has been idle for some time or previous inspection procedures are unknown. For those operations where environmental forces are severe and/or tensioning requirements are high, consideration should be given to maintaining records of individual riser joint placement in the riser string and periodic testing (non-destructive) of the connector and critical weld areas to reduce failures. Refer to APIRP2K: Recommended Practice for Care and Use of Marine Drilling Risers* for specific information.

*Available from American Petroleum Institute, Production Dept. 2535 One Main Place, Dallas TX 75202-3904.

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Figure 9.18 H-4 High-Angle-Release Connector

SEAL RING LOCK PORT PISTON SEAL RING RETAINER SCREW CAM RING CONNECTING ROD

LOCKING DOG

PRIMARY LOCK PORT VENT PORT SECONDARY RELEASE PORT PRIMARY RELEASE PORT PIN MANDREL PROFILE

Vetco's H-4 High-Angle-Release Connector maintains releasing capability under high angles of up to 15° of riser deflection. Minimum swallow of pin mandrel assures quick separation.

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EL Style BOP and Riser Connectors - General Description EL Connectors are hydraulically actuated units which provide ease of operation, positive sealing and field repairability. The connectors are available in a range of sizes at working pressures of 2,000; 5,000 and 10,000 psi. They can be used as a BOP connector, as a riser connector above the BOP, or between BOP components. Features:•

Metal-to-metal primary seal.

•

The large number of locking dogs distribute the load evenly throughout the body and mandrel of the connector.

•

Unit can be serviced without removal from the BOP stack.

•

Optional, secondary resilient seal can be incorporated. This seal is independently energised.

•

Mandrel type construction provides stable engagement before energisation.

•

The 5,000 psi system is completely internally piped.

•

Positive mechanical dogs ensure easy unlatching.

•

Various override mechanisms available.

•

As a riser connector, interchangeability of parts with the BOP connector is possible.

•

Self alignment, five inches before make-up, facilitates choke and kill line stabs.

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Figure 9.20 MCK Valve

The Cameron MCK valve is designed for the rugged service requirements of subsea choke and kill lines.

9 - 44

•

The valve is compact and bolted sideways to the side of the BOP.

•

A detachable actuator allows maintenance to be performed without removing the valve body from the line.

•

Retained seats prevent erosion of the valve.

•

The MCK valve is available in a full range of pressure and bore sizes.

•

Seat and body bushings have been combined into one piece, reducing the number of cavity parts and seals.

•

Balance stem design improves performance.

•

Stem packing can be changed without removing the bonnet from the valve. V4 Rev March 2002


Figure 9.21 Marine Riser Fill-up Valve Riser Fill-up Valve The Cameron riser fill-up valve is designed to prevent the riser from collapsing if the level of drilling fluid drops due to intentional drive-off, loss of circulation, or accidental disconnection of the line. During normal drilling operations, the pressure head created by the mud column inside the riser keeps the valve's internal sleeve closed. When riser pressure drops, ocean pressure pushes the sleeve up, initiating a sequence which fully opens the valve to allow sea water to enter the riser, equalizing the pressure and preventing riser collapse. The riser fill-up valve is activated by the pressure sensory sleeve when the pressure inside the riser is from 250 350 psi below the ambient ocean pressure. When activate, the valve fully opens to rapidly fill the riser. When pressure is equalized, the pressure sensor returns to its normal position and the internal sleeve closes. Although the unit is totally selfcontained and independent of any control lines, the valve can also be manually operated through control lines to the surface.

SD–8140

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SECTION 10 :

FORMULAE, CONVERSION FACTORS & GLOSSARY OF TERMS Page

10. 0

Formulae and Conversion Factors

1

10. 1

Glossary for Well Control Operations

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WELL CONTROL for the Rig-Site Drilling Team SECTION 10 : FORMULAE, CONVERSION FACTORS & GLOSSARY OF TERMS

FORMULAE AND CONVERSION FACTORS 10.0 EQUATION SHEET FOR OILFIELD/FIELD UNITS 1.


=

Mud Weight ppg x 0.052

2.

Mud Weight ppg

=

Pressure Gradient psi/ft ÷ 0.052

3.

Hydrostatic Pressure psi =

Mud Weight ppg x 0.052 x True Vertical Depth ft

4.

Formation Pressure psi (with bit on bottom)

=

Hydrostatic Pressure in Drill String psi + SIDPP psi

5.

Equivalent Mud Weight ppg

=

Pressure psi ÷ True vertical Depth ft ÷ 0.052

6.

Pump Output bbls/min

=

Pump Output bbls/stk x Pump Speed spm

7.

Annulus Velocity ft/min =

Pump Output bbls/min ÷ Annulus Volume bbls/ft

8.

Initial Circulating Pressure psi

=

SCR psi + SIDPP psi

Final Circulating Pressure psi

=

SCR psi x (Kill Mud Weight ppg ÷ Original Mud ppg)

10.

Kill Weight Mud ppg

=

(SIDPP psi ÷ TVD ft ÷ 0.052) + Original Mud ppg

11.

Shut in Casing Pressure psi

=

[(Mud Grad psi/ft - Influx Grad psi/ft) x Influx Height ft] + SIDPP psi

Equivalent circulating density ppg

=

(Annulus Pressure loss psi ÷ TVD ft ÷ 0.052) + Original Mud ppg

Height of influx ft

=

Kick size bbls ÷ Annulus Volume bbls/ft

9.

12.

13.

14.

Gradient of Influx psi/ft =

(SICP psi - SIDPP psi) (Mud weight ppg x 0.052) –––––––––––––––– Influx Height ft

15.

Trip Margin/safety factor ppg

(Safety factor psi ÷ TVD ÷ 0.052) + Mud Weight ppg

16.

Pump Pressure/Pump Stks Relationship psi

V4 Rev March 2002

=

=

Present Pressure psi x (New SPM ÷ Old SPM)2 10- 1


17.

Max. Allowable Mud Weight ppg

=

18.

New MAASP psi

=

19.

Barite to raise mud weight lbs/bbl

=

20.

Percolation Rate ft/hr

=

21.

Kick Tolerance ppg

=

22.

(Surface Leak Off psi ÷ Shoe TVD ft ÷ 0.052) + Test Mud ppg

(Max. Allowable Mud Weight ppg Current Mud Weight ppg) (Kill mud weight ppg - Old mud weight ppg) x 1500 –––––––––––––––––––––––––––––––––––––––––––– (35.8 - kill weight mud ppg) Drill pipe pressure increase psi/hr ÷ Mud gradient psi/ft (MAASP - (Mud gradient psi/ft - Influx Grad ft)) x Influx Height ft –––––––––––––––––––––––––––––––––––––––––––– TVD x 0.052

Kick tolerance in feet

MAASP - SIDPP or [–––––––––––––] = Max Tol Length of Influx GM- GI

Boyle’s Law:

P1V1 = P2V2

P1V1 P2 = –––– V 2

23.

10- 2

Pressure drop per ft. tripping dry pipe

V1P1 V2 = ––––– P2

=

Mud grad psi/ft x Metal Disp bbls/ft –––––––––––––––––––––––––––––– Casing cap. bbls/ft - Metal Disp bbls/ft

24.

Pressure drop per ft. tripping wet pipe

=

Mud grad psi/ft x (Metal disp bbls/ft + Pipe disp bbls/ft) ––––––––––––––––––––––––––––––––––––––––––– Annulus Volume bbls/ft

25.

Level drop for pulling collars out of hole ft

=

Length of collars ft x metal disp bbls/ft ––––––––––––––––––––––––––––––– Casing cap. bbls/ft

26.

Length of pipe to pull before well starts to flow ft

=

Overbalance psi x (casing cap. bbls/ft - pipe disp bbls/ft) ––––––––––––––––––––––––––––––––––––––––––– Mud gradient psi/ft x pipe Disp bbls/ft

27.

Hydrostatic Pressure loss if casing float fails

=

Mud grad psi/ft x Casing Cap bbls/ft x differential height ft –––––––––––––––––––––––––––––––––––––––––––– (casing capacity + Annulus capacity bbls/ft)

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28.

Volume displace by slug

29.

Riser Margin

W2 = Slug Vol x ––– - 1 W 1 ∆P = ––––– ÷ .052 R TVD

[

]

Where ∆P = [Pmud] - [Psw] Riser Sea-water R TVD = [L of hole RKB/TVD] - [L of Riser RKB/BML] or the total increase in mud Wt required before disconnected. [Pmuda + Psw] = P0 30.

D2 Conversion of pipe diameter to bbls/ft = ––––––– = bbls/ft 1029.42

or

31.

D2 - d 2 ––––––– = bbls/ft 1029.42

Max Mud Wt [Offshore] [Psw] + [Pf] ÷ [BML - TVD] ÷ [.052]

32.

Estimated Casing setting depth beneath sea floor [P Mud] - [P sw] ÷ [G.F.B. - G.M] Riser Sea-water

33.

'U' Tube formula SIDPP + [Pmud]DS = [SICP] + [Pmuda] +[Psasa]

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10- 3


APPROPRIATE CONVERSIONS DEPTH

Feet Metres

x 0.3048 to give Metres (m) x 3.2808 to give Feet (ft)

VOLUME

(U.S.) Gallon (U.S.) Barrel Cubic Metre

x 0.003785 to give Cubic Metres (m3) x 0.1590 to give Cubic Metres (M3) x 6.2905 to give Barrel (U.S.)

PRESSURE

PSI KPA Kg/cm2 Bar

x 6.895 to give Kilo Pascals (KPa) x 0.14503 to give Pounds per Square Inch (psi) x 98.1 to give Kilo Pascals (KPa) x 100 to give Kilo Pascals (KPa)

MUD WEIGHT PPG Kg/m3

x 119.8 to give Kilogram per Cubic Metre (Kg/m3) x 0.00835 to give (Pounds per Gallon)

ANNULAR VELOCITY

Feet/Minute Metres/Minute

x 0.3048 to give Metres per Minute (m/min) x 3.2808 to give Feet per Minute (ft/min)

FLOW RATE

Gallons/Minute Barrels/Minute Cubic Metres/Minute Cubic Metres/Minute

x 0.003785 to give Cubic Metres per Minute (m3/min) x 0.159 to give Cubic Metres per Minute (M3/min) x 6.2905 to give Barrels per Minute (bbl/min) x 264.2 to give Gallons per Minute (gals/min)

FORCE Pound Force (eg WEIGHT ON BIT) Decanewtons

x 0.445 to give Decanewtons x 2.2472 to give Pound Force

MASS

Pounds

x 0.454 to give Kilograms (Kg)

Tons (Long-2240 lbs)

x 1017 to give Kilograms (Kg)

Tonnes (Metre-2205 lbs)

x 1001 to give Kilograms (Kg)

Kilograms

x 2.2026 to give Pounds (lbs)

PSI/Foot KPa/Metre

x 22.62 to give Kilo Pascals per Metre (K/Pa/m) x 0.04421 to give Pounds per Square Inch per Foot (psi/ft)

PRESSURE GRADIENT

MUD WEIGHT PPG TO PRESSURE GRADIENT SG b/ft3 Kg/m3 3

Kg/m 10- 4

or

x 0.052 to give Pounds per Square Inch per Foot (psi/ft) [Pressure Gradient] x .433 to give Pounds per Square Inch per Foot (psi/ft) ÷ 144 to give Pounds per Square Inch per Foot (psi/ft) x 0.000434 to give Pounds per Square Inch ÷ 2303 per Foot (psi/ft) x 0.00982 to give Kilo Pascals per Metre (K/Pa/m) V4 Rev March 2002


10.1 GLOSSARY FOR WELL CONTROL OPERATIONS Abnormal Pressure - Pore pressure in excess of that pressure resulting from the hydrostatic pressure exerted by a vertical column of water salinity normal for the geographic area. Accumulator - A vessel containing both hydraulic fluid and gas stored under pressure as a source of fluid power to operate opening and closing of blowout preventer rams and annular preventer elements. Accumulators supply energy for connectors and valves remotely controlled. Accumulator Bank Isolator Valve - The opening and closing device located upstream of the accumulators in the accumulator piping which stops flow of fluids and pressure in the piping. Accumulator Relief Valve - The automatic device located in the accumulator piping that opens when the pre-set pressure limit has been reached so as to release the excess pressure and protect the accumulators. Accumulator Unit - The assembly of pumps, valves, lines, accumulators, and other items necessary to open and close the blowout preventer equipment. Air Breather - A device permitting air movement between the atmosphere and the component in which it is installed. Air Pressure Switch Bypass Valve - The opening and closing device located in the air supply line which blocks air flow in one line to be redirected through another. In open position, air flow is not routed through the air pressure switch for automatic shutoff thereby allowing the air pumps to continue to run. Air Pump Suction Valve - The opening and closing device located in the piping line that draws fluid from the reservoir into the fluid end of the pump when the air motor is operating. Air Regulator - The adjusting device to vary the amount of air pressure entering as to the amount to be discharged down the piping lines. Air Supply Valve - The opening and closing device in the connecting line of the compressed air routed to flow into the accumulator system lines as a power source for components. Ambient Temperature - The temperature of all the encompassing atmosphere within a given area. Ampere - The unit used for measuring the quantity of an electric current flow. One ampere represents a flow of one coulomb per second.

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Annular - A large valve, usually installed above the ram preventers, that forms a seal in the space between the pipe and wellbore or on the wellbore itself. The space around a pipe in a wellbore, the outer wall of which may be the wall of either the borehole or the casing. Annular Preventer - A device which can seal around any object in the wellbore or upon itself. Compression of a reinforced elastomer packing element by hydraulic pressure effects the seal. Annular Regulator - The device located in the annular manifold header to enable adjustment of pressure levels which will flow past to control the amount of closure of the annular preventer. Annulus Friction Pressure - Circulating pressure loss inherent in annulus between the drill string and casing or open hole. Back Pressure (Casing Pressure, Choke Pressure) - The pressure existing at the surface on the casing side of the drill pipe/annulus flow system. Baffle - A partition plate inside the reservoir to prevent unbalancing by sudden weight shifting of the hydraulic fluid. Barite Plug - A settled volume of barite particles from a barite slurry placed in the wellbore to seal off a pressured zone. Barite Slurry - A mixture of barium sulphate, chemicals, and water of a unit density between 18 and 22 pounds per gallon (lb/gal). Belching - A slang term to denote flowing by heads. Bell Nipple (Mud Riser, Flow Nipple) - A piece of pipe, with inside diameter equal to or greater than the blowout preventer bore, connected to the top of the blowout preventer or marine riser with a side outlet to direct the drilling fluid returns to the shale shaker or pit. Usually has a second side outlet for the fill-up line connection. Bleeding - Controlled release of fluids form a closed and pressured system in order to reduce the pressure. Blind Rams (Blank, Master) - Rams whose ends are not intended to seal against any drill pipe or casing. They seal against each other to effectively close the hole. Blind/Shear Rams - Blind rams with a built-in cutting edge that will shear tubulars that may be in the hole, thus allowing the blind rams to seal the hole. Used primarily in subsea systems.

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Blowout - An uncontrolled flow of gas, oil, or other well fluids into the atmosphere. A blowout, or gusher, occurs when formation pressure exceeds the pressure applied to it by the column of drilling fluid. Blowout Preventer - The equipment installed at the wellhead to enable the driller to prevent damage at the surface while restoring the balance between the pressure exerted by the column of drilling fluid and formation pressure. The BOP allows the well to be sealed to confine the well fluids and prevent the escape of pressure either in the annular space between the casing and drill pipe or in an open hole. The blowout preventer is located beneath the rig at the land’s surface on land rigs or at the water’s surface on jack-up or platform rigs and on the sea floor for floating offshore rigs. Blowout Preventer Drill - A training procedure to determine that rig crews are completely familiar with correct operating practices to be followed in the use of blowout prevention. A dry run of blowout preventive action. Blowout Preventer Operating and Control System (Closing Unit) - The assembly of pumps, valve, lines, accumulators and other items necessary to open and close the blowout preventer equipment. Blowout Preventer Stack - The assembly of well control equipment including preventers , spools, valves and nipples connected to the top of the wellhead. Blowout Preventer Test Tool - A tool to allow pressure testing of the blowout preventers stack and accessory equipment by sealing the wellbore immediately below the stack. Bleeder Valve - An opening and closing device for removal of pressurised fluid. Borehole Pressure - Total pressure exerted in the wellbore by a column of fluid and/or back pressure imposed at the surface. Bottom-hole Pressure - Depending upon context, either a pressure exerted by a column of fluid contained in the wellbore or the formation pressure at the depth of interest. Broaching - Venting of fluids to the surface or to the sea-bed through channels external to the casing. Bullheading - A term to denote pumping into a closed-in well without returns. Casinghead/Spool - The part of the wellhead to which the blowout preventer stack is connected. Casing Pressure - see Back Pressure.

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Casing Seat Test - A procedure whereby the formation immediately below the casing shore is subjected to a pressure equal to the pressure expected to be exerted later by a higher drilling fluid density or by the sum of a higher drilling fluid density and back pressure created by a kick. Chain Guard - The metal enclosure surrounding the electric pump driving chain to protect and contain an oil lubricate for the chain. Check Valve - A valve that permits flow in only one direction. Choke - A variable diameter orifice installed in a line through which high pressure well fluids can be restricted or released at a controlled rate. Chokes also control the rate of flow of the drilling mud out of the hole when the well is closed in with the blowout preventer and a kick is being circulated out of the hole. Choke Line - The high pressure piping between blowout preventer outlets or wellhead outlets and the choke manifold. Choke Line Valve - The valve(s) connected to and a part of the blowout preventer stack that control the flow to the choke manifold. Choke Manifold (Control Manifold) - The system of valves, chokes, and piping to control flow from the annulus and regulate pressures in the drill pipe/annulus flow system. Choke Pressure - See Back Pressure. Circuit Breaker - An electrical switching device able to carry an electrical current and automatically break the current to interrupt the electrical circuit if adverse conditions such as shorts or overloads occur. Circulating Head - A device attached to the top of drill pipe or tubing to allow pumping into the well without use of the kelly. Clamp Connection - A pressure sealing device used to join two items without using conventional bolted flange joints. The two items to be sealed are prepared with clamp hubs. These hubs are held together by a clamp containing two to four bolts. Closing Unit - The assembly of pumps, valves, lines, accumulators and other items necessary to open and close the blowout preventer equipment. Closing Ratio - the ratio of the wellhead pressure to the pressure required to close the blowout preventer. Conductivity - The capability of a material to carry an electrical charge. Usually expressed as a percentage of copper conductivity (copper being one hundred 100 10- 8

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percent). Conductivity is expressed for a standard configuration of conductor. Conductor - The substance or body capable of transmitting electricity, heat, light, or sound. Conductor Pipe - A relatively short string of large diameter pipe which is set to keep the top of the hole open and provide a means of returning the upflowing drilling fluid from the wellbore to the surface drilling fluid system until the first casing string is set in the well. Conductor pipe is usually cemented. Continuity - The uninterrupted flow of current in a conductor. Contract Block - The conductor located in the electric panels which bring together the electrical connections of the operation pushbuttons with those of the operator valves. Control Manifold - The system of valves and piping used to control the flow of pressured hydraulic fluid to operate the various components of the blowout preventer stack. Control Panel, Remote - A panel containing a series of control that will operate the valves on the control manifold from a remote point. Control Pod - An assembly of subsea valves and regulators which when activated from he surface will direct hydraulic fluid through special apertures to operate blowout preventer equipment. Corrosion Inhibitor - Any substance which slows or prevents the chemical reactions of corrosion. Cut Drilling Fluid - Well control fluid which has been reduced in density or unit weight as a result of entrainment of less dense formation fluids or air. Cylinder - A device which converts fluid or air power into linear mechanical force and motion. It consists of a movable element such as a piston and piston rod, plunger rod, plunger or ram, operating within a cylindrical chamber. Degasser - A vessel which utilizes pressure reduction and/or inertia to separate entrained gases from the liquid phases. Discharge Check Valve - The device located in the expelling line of a pump (air or electric) which allows fluid to flow out only and thereby prevents a back flow of fluid into the pump. Displacement - The volume of steel in the tubulars and devices inserted and/or withdrawn from the wellbore.

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Diverter - A device attached to the wellhead or marine riser to close the vertical access and direct any flow into a line away from the rig. Drain Port - The plugged openings on the lower side portions of the reservoir which can be opened to empty or release the hydraulic fluid, and through which the reservoir can be cleaned. Drilling Fluid Weight Recorder - An instrument in the drilling fluid system which continuously measures drilling fluid density. Drilling Spool - A connection component with ends either flanged or hubbed. It must have an internal diameter at least equal to the bore of the blowout preventer and can have smaller side outlets for connecting auxiliary lines. Drill Pipe Safety Valve - An essentially full-opening valve located on the rig floor with threads to match the drill pipe in use. This valve is used to close off the drill pipe to prevent flow. Drill Stem Test (DST) - A test conducted to determine production flow rate and/ or formation pressure prior to completing the well. Drill String Float - A check valve in the drill string that will allow fluid to be pumped into the well but will prevent flow from the well through the drill pipe. Drive Pipe - A relatively short string of large diameter pipe driven or forced into the ground to function as conductors pipe. Dust Cap - The screw on covering for the electric panel connector receptacles which protect the electrical contacts from foreign matter and moisture. Electric Pump Suction Valve - The opening and closing device located in the piping line that draws fluid from the reservoir into the pump inlet when the motor is operating. Element (Filter) - The substance of porous nature which retains foreign particles that pass through the containing chamber to separate and clean the gas or liquid flow. Equivalent Circulating Density (ECD) - The sum of pressure exerted by hydrostatic head of fluid, drilled solids, and friction pressure losses in the annulus divided by depth of interest and by 0.052, if ECD is to be expressed in pounds per gallon (lb/gal). Feed-in (Influx, Inflow) - The flow of fluids from the formation into the wellbore. Fill Port - The plugged opening in the top of the fluid reservoir through which hydraulic oil is added.

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Fill-up Line - A line usually connected into the bell nipple above the blowout preventers to allow adding drilling fluid to the hole while pulling out of the hole to compensate for the metal volume displacement of the drill string being pulled. Filter (Air) - Apparatus used to clean air flow of dirt, moisture and other contaminants. Filter (Hydraulic) - A device whose function is the retention of insoluble contaminants from a fluid. Final Circulating Pressure - Drill pipe pressure required to circulate at the selected kill rate adjusted for increase in kill drilling fluid density over the original drilling fluid density; used from the time kill drilling fluid reaches the bottom of the drill string until kill operations are completed or a change in either kill drilling fluid density or kill rate is effected. Flow Meter - A device which indicates either flow rate, total flow, or a combination of both, that travels through a conductor such as pipe or tubing. Flow Rate - The volume, mass, or weight of a fluid passing through any conductor, such as pipe or tubing, per unit of time. Fluid - A substance that flows and yields to any force tending to change its shape. Liquids and gases are fluids. The accumulator system pressurises fluid to be used as a source of power to open and close valves and rams on the BOP stack. Fluid Density - The unit weight of fluid; e.g., pounds per gallon (lb/gal). Formation Breakdown - An event occurring when borehole pressure is of magnitude that the exposed formation accepts whole fluid from the borehole. Formation Competency (Formation Integrity) - The ability of the formation to withstand applied pressure. Formation Competency Test (Formation Integrity Test) - Application of pressure by superimposing a surface pressure on a fluid column in order to determine ability of a subsurface zone to withstand a certain hydrostatic pressure. Formation Integrity - See Formation Competency. Formation Integrity Test - See Formation Competency Test. Formation Pressure (Pore Pressure) - Pressure exerted by fluids within the pores of the formation (see Pore Pressure). Flowline Sensor - A device to monitor rate of fluid flow from the annulus. Fracture Gradient (Frac. Gradient) - The pressure gradient (psi/ft) at which the V4 Rev March 2002

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formation accepts whole fluid from the wellbore. Full Load Current - The amount of current used by an electrical circuit when the circuit is operating at its designed or rated maximum capacity. Function - The term given to the duty of operating the control valves of the accumulator system. The action performed by the control valves when operating the ram preventers or gate valves. Gage - A standard method of specifying the physical size of a conductor (wire) diameter based on the circular mil system. 1 mil equals .001. The higher the number, the smaller the diameter. Gas Buster - A slang term to denote a mud gas separator. Gate Valve - A valve which employs a sliding gate to open or close the flow passage. The valve may or may not be full-opening. Gauge - An instrument for measuring fluid pressure that usually registers the difference between atmospheric pressure and the pressure of the fluid by indicating the effect of such pressure on a measuring element (as a column of liquid, a bourdon tube, a weighted piston, a diaphragm, or other pressuresensitive devices). Gland - The cavity of a stuffing box. Ground - An electrical term meaning to connect to the earth, or another large conducting body to serve as earth, thus making a complete electrical circuit. The conducting connection of a circuit to the earth. Gunk Plug - A volume of gunk slurry placed in the wellbore. Gunk Slurry - A slang term to denote a mixture of diesel oil and bentonite. Gunk Squeeze - Procedure whereby a gunk slurry is pumped into a subsurface zone. H S - An abbreviation for hydrogen sulphide. 2 Hard Close In - To close in a well by closing a blowout preventer with the choke and/or choke line valve closed. Hydrostatic - Relating to liquids at rest and the pressure they exert. Hydrostatic Head - The true vertical length of fluid column, normally in feet. Hydrostatic Pressure (Hydrostatic Head) - The pressure which exists at any point 10- 12

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in the wellbore due to the weight of the vertical column of fluid above that point. Indicating Light - The bulbs of the electric control panels that shine to point out which electrical contacts have made a circuit. The electric panel bulbs make circuit contacts through pressure switches, transducers, and solenoid valves to demonstrate activation. Inflow - See Feed-in. Influx - See Feed-in. Initial Circulating Pressure - Drill pipe pressure required to circulate initially at the selected kill rate while holding casing pressure at the close-in value; numerically equal to kill rate circulating pressure plus closed-in drill pipe pressure. Inside Blowout Preventer - A device that can be installed in the drill string that acts as a check valve allowing drilling fluid to be circulated down the string but prevents back flow. Inspection Port - The plugged openings on the sides of the fluid reservoir which can be opened to view the interior fluid level and return lines from the relief, bleeder, control valves, and regulators. Insulation - A non-conductive material usually surrounding or separating the current carrying parts from each other or from the core. Kelly Cock - A valve immediately above the kelly that can be closed to confine pressures inside the drill string. Kelly Valve - Lower. An essentially full opening valve installed immediately below the kelly with outside diameter equal to the tool joint outside diameter. Kick - Intrusion of formation fluids into the wellbore. Kill Drilling Fluid Density - The unit weight e.g. pounds per gallon (lb/gal), selected for the fluid to be used to contain a kicking formation. Kill Line - A high-pressure fluid line connecting the mud pump and the wellhead at some point below a blowout preventer. This line allows heavy drilling fluids to be pumped into the well or annulus with the blowout preventer closed to control a threatened blowout. Kill Rate - A predetermined fluid circulating rate, expressed in fluid volume per unit time, which is to be used to circulate under kick conditions; kill rate is usually some selected fraction of the circulating rate used while drilling.

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Kill Rate Circulating Pressure - Pump pressure required to circulate kill rate volume under non-kick conditions. Leak-off Test - Application of pressure by superimposing a surface pressure on a fluid column in order to determine the pressure at which the exposed formation accepts whole fluid. Lost Circulation (Lost Returns) - The loss of whole drilling fluid to the wellbore. Lost Returns - See Lost Circulation. Lubrication. Alternately pumping a relatively small volume of fluid into a closed wellbore system and waiting for the fluid to fall toward the bottom of the well. Lubricator (Air) - A device which adds controlled or metered amounts of a substance into the air line of a fluid power system to prevent or lessen friction. Manifold Bleeder Valve - The opening and closing device in the piping that connects the manifold header and the reservoir, and which can be opened to release the fluid pressure and vent it back into the reservoir. Manifold Header - The piping system which serves to divide a flow through several possible outlets. The 4-Way control valve inlets connect to the piping so that high pressure fluid is available to pass through any or all of the valves. Manifold Regulator - The device located in the manifold header which can vary the amount of pressure that enters and exits its chamber. The manifold regulator controls the pressure level of the fluid flowing through and out the 4-Way control valves. Manifold Regulator Bypass Valve - The opening and closing device which blocks flow in one line to be redirected through another. This valve is located in the manifold piping so that in the open position the high pressure fluid does not flow through the regulator in the manifold header, thereby allowing higher pressure fluid to be available to the 4-Way control valves. Manifold Relief Valve - The automatic opening device located on the manifold header that opens when the present pressure limit has been reached so any excess pressure is released, thereby protecting the manifold header. Meter - An instrument, operated by an electrical signal, that indicates a measurement of pressure. Meter Circuit Board - Printed circuit board used with the electrical meters to provide the circuits necessary for calibration of the meter. Micron - (A millionth of a meter or about 0.0004 inch). The measuring unit of the 10- 14

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porosity of filter elements. Mil - A measurement used in determining the area of wire. The area of a circle one 1/thousandth inch in diameter. Minimum Internal Yield Pressure - The lowest pressure at which permanent deformation will occur. Motor Starter - Automatic device which starts or stops the electric motor driving the duplex or triplex pump which works in conjunction with the automatic electrical pressure switch for pressure limits of pump start-up and shutoff. Mud-gas Separator - A vessel for removing free gas from the drilling fluid returns. Needle Valve - A shutoff (2-Way) valve that incorporates a needle point to allow fine adjustments in flow. Normal Pressure - Formation pressure equal to the pressure exerted by a vertical column of water with salinity normal for the geographic area. Ohm - A unit of electrical resistance, the resistance of a circuit in which a potential difference of one volt produces a current of one ampere. Ohmmeter - The measuring instrument which indicates resistance in ohms. Opening Ratio - The ration of the well pressure to the pressure required to open the blowout preventer. Overbalance - The amount by which pressure exerted by the hydrostatic head of fluid in the wellbore exceeds formation pressure. Overburden - The pressure on a formation due to the weight of the earth material above that formation. For practical purposes this pressure can be estimated at 1 psi/ft of depth. Packoff or Stripper - A device with an elastomer packing element that depends on pressure below the packing to effect a seal in the annulus. Used primarily to run or pull pipe under low or moderate pressures. This device is not dependable for service under high differential pressures. Petcock - The small faucet or valve used to release compression or drain moisture accumulated in the anterior chamber of the lubricator. Phase (3-Phase Motor) - A particular stage or point of advancement in an electrical cycle. The fractional part of the period through which the time has advanced, measured from some arbitrary point usually expressed in electrical degrees where 360° represents one cycle. V4 Rev March 2002

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Pipe Rack - The connecting pipelines between the control valve outlets and the BOP stack preventers which carry the high pressure operating fluid. The lines of pipe are laid together and are often covered with a grating to create a walkway. Pipe Rams - Rams whose ends are contoured to seal around pipe to close the annular space. Separate rams are necessary for each size (outside diameter) pipe in use. Pit Volume Indicator - A device installed in the drilling fluid tank to register the fluid level in the tank. Pit Volume Totaliser - A device that combines all of the individual pit volume indicators and registers the total drilling fluid volume in the various tanks. Plug Valve - A valve whose mechanism consists of a plug with a hole through it on the same axis as the direction of fluid flow. Turning the plug 90 opens or closes the valve. The valve may or may not be full-opening. Pore Pressure (Formation Pressure) - Pressure exerted by the fluids within the pore space of a formation. Potable - A liquid that is suitable for drinking. Pressure Gradient, Normal - The normal pressure divided by true vertical depth. Pressure Switch (Air) - The automatic device to start and stop the air pump operation when the present pressure limits are reached. Pressure Switch (Electric) - An electrical switch, operated by fluid pressure, which automatically starts and stops the electrical pump when the present pressures are reached. Pressure Transmitter - Device which sends a pressure signal to be converted and calibrated to register the equal pressure reading on a gauge. The air output pressure in proportion to the hydraulic input pressure. Primary Well Control - Prevention of formation fluid flow by maintaining a hydrostatic pressure equal to or greater than formation pressure. Pump (Air) - A device that increases the pressure on a fluid or raises it to a higher level by being compressed in a chamber by a piston operated with an air pressure motor. Pump (Electric) - A device that increases the pressure on a fluid and moves it to a higher level using compression force from a chamber and piston that is driven by an electric motor.

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Pushbutton/Indicating Light - The control valve operates with bulbs on the electrical remote panel which change and indicate the position of the control valves. Ram - The closing and sealing component on a blowout preventer. One of three types - blind, pipe, or shear - may be installed in several preventers, mounted in a stack on top of the wellbore. Blind rams, when closed, form a seal on a hole that has no drill pipe in it; pipe rams, when closed, seal around the pipe; shear rams cut through drillpipe and then form a seal. Recorder - An automatic device that reads and records pressure outputs continually on a revolving chart to provide continuous evidence of pressures. Regulator - A device that varies and controls the amount of pressure of a liquid or gas that passes through its chambers. Relay - An electrical device to automatically control the operation of another device in another circuit by passing on an electric current. Relay Socket - A device used to interconnect a relay with its circuitry and which allows quick and easy removal of the relay without special tools. Relief Well - An offset well drilled to intersect the subsurface formation to combat blowout. Replacement - The process whereby a volume of fluid equal to the volume of steel in tubulars and tools withdrawn from the wellbore is returned to the wellbore. Reservoir - The container for storage of liquid. The reservoir houses hydraulic fluid at atmospheric pressure as the supply for fluid power. Resistance - The property of an electrical circuit which determines for a given current, the rate at which electrical energy is converted into heat and has a value such that the current squared, multiplied by the resistance, gives the power converted. Rotating Head - A rotating, low pressure sealing device used in drilling operations to seal around the drill stem above the top of the blowout preventer stack. Rupture Disk - A device whose breaking strength (the point at which it physically comes apart) works to relieve pressure in the system. The rupture disk is contained as a safety device for the test unit system. Safety Factor - In the context of this publication, an incremental increase in drilling fluid density beyond the drilling fluid density indicated by calculations to be needed to contain a kicking formation. V4 Rev March 2002

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Salt Water Flow - An influx of formation salt water into the wellbore. Shear Rams - Blowout preventer rams with a built in cutting edge that will shear tubulars that may be in the hole. Soft close In - To close in a well by closing a blowout preventer with the choke and choke line valve open, then closing the choke while monitoring the casing pressure gauge for maximum allowable casing pressure. Solenoid Valve - The opening/closing device which is activated by an electrical signal to control liquid or gas pressured flow to be sent to open or close the 4-Way control valves. The valve position is controlled by an electromagnetic bar, enclosed by a coil. Solenoid Valve Box - The explosion proof enclosure, located on the accumulator unit, which contains the electrically powered actuators for the remote control electrical panel. The box is wired to the electrical supply, and houses solenoid valves, pressure switches and transducers. Sour Gas - Natural gas containing hydrogen sulphide. Space Out - Procedure conducted to position a predetermined length of drill pipe above the rotary table so that a tool joint is located above the subsea preventer rams on which drill pipe is to be suspended (hung-off) and so that no tool joint is opposite a set of preventer rams after drill pipe is hung-off. Space-Out Joint - The joint of drill pipe which is used to hang off operations so that no tool joint is opposite a set of preventer rams. Span Adjustment - The control to vary the space between the electrical contact points in the electrical pressure switch. Squeezing - Pumping fluid into one side of the drill pipe/annulus flow system with the other side closed so as to allow no outflows. Stack - The assembly of well control equipment including preventers, spools, valves, and nipples connected to the top of the casing head. Strainer - A porous material which retains contaminants passing through a line along with the gas or liquid flow. Suction Strainer - The porous element, located in a “y” shaped fitting of the pump suction lines, which cleans the hydraulic fluid or air of contaminants before entering the pumps. Surge Damper - The one quart capacity bladder accumulator used to absorb the shock and waves caused by an initial flow of high pressure fluid. Located in the downstream line of the annular regulator. 10- 18

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Swabbing - The lowering of the hydrostatic pressure in the wellbore due to upward movement of tubulars and/or tools. Swivel Joint - A connecting device, joining parts so that each can pivot freely. Swivel joints are used at the ends of the pipe rack to ease connections to the control valve outlets and to the BOP stack. Target - A bull plug or blind flange at the end of a T to prevent erosion at a point where change in flow direction occurs. Targeted - Refers to a fluid piping system in which flow impinges upon a leadfilled end (target) or a piping T when fluid transits a change in direction. Terminal Strip - Grouped electrical conductor endings where screw connections are made. Transducer - The device located in the solenoid valve box which is actuated by hydraulic pressure and converts the force to an electrical force for indication on a meter. The electrical output signal is in proportion to the hydraulic input pressure. Trip Gas - An accumulation of gas which enters the hole while a trip is made. Trip Margin - An incremental increase in drilling fluid density to provide an increment of overbalance in order to compensate for effects of swabbing. Tubulars - Drill pipe, drill collars, tubing, and casing. Underground Blowout - An uncontrolled flow of formation fluids from a subsurface zone into a second subsurface zone. Underbalance - The amount by which formation pressure exceeds pressure exerted by the hydrostatic head of fluid in the wellbore. Unit/Remote Selector - The valve located on the manifold header whose ports allow flow into the annular regulator. The valve position determines the source of flow supply and subsequently controls the location of operation. Valve, Float - A device that is positioned as either open or closed, depending on the position of a lever connected to a buoyant material sitting in the fluid to be monitored. Valve, Manipulator - A control device having three positions, giving four direction selections for flow which alternately pressurises and vents the pressure outlets. The manipulator style valve vents all pressure outlets when placed in the centre position. Valve, Poppet - The opening and closing device in a line of flow which restricts flow by lowering a piston type plunger into the valve passageway. V4 Rev March 2002

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Valve, Pre-charge - The device located on the accumulator bladder ports which open and close for the nitrogen pressure contained. Valve, Relief - A valve that opens at a present pressure to relieve excessive pressures within a vessel or line whose primary function is to limit system pressure. Valve, Selector - A control device having three positions, giving four direction selections for flow which alternately pressurises and vents the pressure outlets. The selector style valve blocks all pressure points if placed in the centre position. Valve, Shutoff - A valve which operates fully open or fully closed to control the flow through the lines. Valve, Shuttle - A connective valve which selects one of two or more circuits because flow or pressure changes between the circuits. Viscosity - A measure of the internal friction or the resistance of a fluid to flow. Volt - A unit of electromotive force. Watt - A unit of electrical power; the power of one ampere of current pushed by one volt of electromotive force. Weight Cut - The amount by which drilling fluid density is reduced by entrained formation fluids or air. Wireline Preventers - Preventers installed on top of the well or drill string as a precautionary measure while running wirelines. The preventer packing will close around the wireline. Zero Adjustment - The control to move the meter gauge indicator for resetting calibration accuracy. Control used to make the meter read 0 by applying an offset voltage to the meter to offset any positive voltage present at the meter, even though there is no pressure at the input of the transducer.

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ABERDEEN Drilling Schools - Well Control.pdf

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