Iwcf Section One

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The purpose of this manual is to support classroom study and discussions in preparation for the IWCF Well Intervention Pressure Control Examination. It is not intended to be a definitive document.

This manual has been developed by Caledonia Training and Consultancy Ltd., Aberdeen and remains their property. It may not be copied, reproduced, stored in a retrieval system or transmitted in whole or in part, in any form or by any means electronic, mechanical, photographic, recorded or otherwise without the express written permission of Caledonia Training and Consultancy Ltd.

Caledonia Training and Consultancy Ltd. has a policy of continually updating and upgrading all its training material and reserves the right to make changes to this manual without notice to its current holders.

Every effort has been made to ensure the accuracy of this manual; however no responsibility can be accepted by Caledonia Training and Consultancy Ltd. concerning the use or interpretation of information contained within.


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Well Intervention Pressure Control

1. REASONS FOR WELL INTERVENTIONS 12

1.1 GENERAL 12 1.1.1 Tubing Blockage 13

1.1.2 Excessive Water or Gas Production 14

1.1.3 Control of Gas Production 18

1.1.4 Mechanical Failure 19

1.1.5 Stimulation of Low Production Wells 20

1.1.6 Partially Depleted Reservoirs 21

1.1.7 Sand Control 21

2. COMPLETIONS. 24

2.1 FUNCTIONAL REQUIREMENTS OF A COMPLETION 24

2.2 COMPLETION EQUIPMENT 24 2.2.1 Tubing 25

2.2.2 Wireline re-entry guide 26

2.2.3 Blast Joints 28

2.2.4 Protection Joint 28

2.2.5 Perforated Joints 28

2.2.6 Landing Nipples 28

2.2.7 Flow Couplings 30

2.3 FLOW CONTROL DEVICES 30 2.3.1 Tubing hanger plugs. 30

2.3.2 Wireline type plugs 30

2.3.3 Threaded plugs 30

2.3.4 Blanking Plugs 33

2.3.5 Check Valves (Standing Valves) 33

2.3.6 Pump Through Plugs 33

2.3.7 Pump Open Plugs 33

2.3.8 Expendable Plugs 33

2.3.9 Cycle Plugs 33

2.3.10 Ice Plugs ( Freeze Method ) 33

2.4 PACKERS 33




2.4.1 Retrievable Packers 34

2.4.2 Permanent Packers 34

2.4.3 Retrievable Packer Accessories 34

2.4.4 Permanent Packer Accessories 37

2.5 CIRCULATION DEVICES 41 2.5.1 SLIDING SIDE DOORS 41

2.5.2 Side Pocket Mandrels 43

2.6 SUB-SURFACE SAFETY VALVES (SSSV) 47

2.7 TYPES OF SUB-SURFACE SAFETY VALVES 48

2.8 SCSSSV 48 2.8.1 Pressure-Differential Safety Valves 48

2.8.2 Ambient Safety Valves 49

2.8.3 Injection Valve 49

2.8.4 Surface Controlled Sub-Surface Safety Valve 50

2.8.5 Wireline Retrievable SCSSV 50

2.8.6 Running in hole. 51

2.8.7 Tubing Retrievable SCSSV 53

2.8.8 Running in Hole. 53

2.8.9 Leak Off Testing 53

2.8.10 Reliability 54

2.8.11 Annular Safety Valves 54

2.9 SCSSV SETTING DEPTH 57

2.10 SURFACE CONTROL MANIFOLDS 57 2.10.1 Tubing Head/Tubing Hanger 58

2.11 CHRISTMAS TREES 60 2.11.1 Christmas Tree Valves 60

2.12 TYPES OF CHRISTMAS TREE 62 2.12.1 Composite trees 62

2.12.2 Solid Block Tree 62

2.12.3 Horizontal Trees 62

2.13 SURFACE EQUIPMENT - GENERAL 65 2.13.1 Chokes 65

2.13.2 Fixed Choke 65

2.13.3 Adjustable Choke 65

2.14 EQUIPMENT AND RISER CONNECTIONS 68




2.14.1 Quick Unions 68

2.14.2 Clamp Connections 69

2.14.3 Flange connections 70

2.14.4 Design 71

2.14.5 Type ‘6B’ Flanges 71

2.14.6 Gaskets. 71

2.14.7 Ring Gaskets 73

3. WELL CONTROL GENERAL (P&P) 77

3.1 HYDROSTATIC PRESSURE 77 3.1.1 Derivation of the constant 0.433 78

3.1.2 Derivation of the constant 0.052 79

3.1.3 Formation Gradient 80

3.2 GASSES 80 3.2.1 hydrostatic head of a column of gas. 81

3.3 FORMATION PRESSURE 83 3.3.1 Volumes 85

3.3.2 Hydrostatic/Volume Example 85

3.3.3 Tubing Closed end Displacement 87

3.3.4 Bottoms Up 87

3.4 THIEF ZONES 88

3.5 BARRIER PHILOSOPHY 88

3.6 BARRIER CLASSIFICATION 89 3.6.1 Containment Devices 89

3.7 TYPES OF MECHANICAL BARRIER 89 3.7.1 Closed Barriers 89

3.7.2 Closable Barriers 89

3.7.3 Hydrostatic Barriers 90

3.8 BARRIER ENVELOPES 90 3.8.1 Barrier Testing and Inflow Testing 93

3.9 PRODUCTION WELL KILL PROCEDURES 93




3.9.1 Forward circulation 93

3.9.2 Reverse circulation 97

3.9.3 Bullheading 102

3.9.4 Lubricate and Bleed 103

3.10 WORKOVER FLUIDS 105

3.11 SOLIDS BEARING FLUIDS 106

3.12 SPECIALITY COMPLETION FLUIDS 106 3.12.1 Solids Free Completion Fluids 106

3.13 COMPOSITION OF BRINES 107 3.13.1 Brine Selection 107

3.14 HYDRATES 107

4. WIRELINE 113

4.1 SLICKLINE 113

4.2 SURFACE EQUIPMENT 116 4.2.1 Power Unit 116

4.2.2 Winch 116

4.2.3 Pressure Control Equipment 118

4.2.4 Hydraulc Tool Catcher 128

4.3 ANCILLARY EQUIPMENT 128 4.3.1 Chemical Injection Sub 128

4.3.2 Cutter Valves 130

4.4 WIRELINE BARRIER PHILOSOPHY 131

4.5 RISERS AND CONNECTIONS 131

4.6 OPERATIONS 132

4.7 CONTINGENCIES 134 4.7.1 Leak in surface equipment above the BOP. 134

4.7.2 Wire pulled out of rope socket. 134

4.7.3 Power Pack Failure 134

4.8 WELL CONTROL PROBLEMS 135

4.9 BRAIDED LINE 136

4.10 ELECTRIC LINE 136




4.10.1 braided line Pressure control Equipment 137

4.10.2 Grease Injection Head 139

4.10.3 Flow Tubes 139

4.10.4 Pack off 139

4.10.5 Safety Check Union 142

4.10.6 Dual BOP 142

4.10.7 Pressure Testing 142

4.11 OPERATIONS 143 4.11.1 Contingencies 143

5. COILED TUBING 144

5.1 GENERAL 145

5.2 COILED TUBING EQUIPMENT 148 5.2.1 Surface Equipment 148

5.2.2 Power Unit 148

5.2.3 Control Cabin 149

5.2.4 Tubing Reel 149

5.2.5 Injector Head 150

5.3 PRESSURE CONTROL EQUIPMENT 153 5.3.1 Stripper 153

5.3.2 Ram Type BOP’s 157

5.3.3 Quad BOP 158

5.3.4 Combi 162

5.3.5 Triple BOP’s 165

5.3.6 Shear/Seal (Safety Head) 165

5.3.7 Annular BOP’s 165

5.3.8 Check Valves 168

5.4 RISERS AND CONNECTIONS 169

5.5 DEPLOYMENT SYSTEMS 169

5.6 OTHER SURFACE EQUIPMENT 171 5.6.1 Lifting Frame 171

5.6.2 Support Frames 171

5.6.3 Downhole Pressure Control Devices 172

5.7 OTHER DOWNHOLE TOOLS 172




5.7.1 Shear Subs 172

5.8 OPERATIONS 173 5.8.1 Contingencies 174

6. SNUBBING 179

6.1 HWO 180

6.2 SURFACE EQUIPMENT 187 6.2.1 Hydraulic Jack 187

6.2.2 Guide tubes 187

6.2.3 Access Window 187

6.2.4 Slips 188

6.2.5 Rotary Table 190

6.2.6 Work Basket 190

6.2.7 Counter Balance 190

6.2.8 Power Pack 190

6.2.9 Power Tongs 191

6.2.10 Guy Wires 191

6.2.11 Other Equipment 191

6.3 PRESSURE CONTROL EQUIPMENT 192

6.4 STRIPPER BOWL 192 6.4.1 Annular BOP 192

6.4.2 Stripping BOP’s 194

6.4.3 Stripping Ram Seals 195

6.4.4 Equalising Loop 197

6.4.5 Bleed Off Line 197

6.4.6 Ram Type BOP’s 197

6.4.7 Cameron U BOP 197

6.4.8 Shear and Seal BOP’s 198

6.4.9 Risers and Connections 198

6.4.10 BOP Control Skid 198

6.5 BARRIER PHILOSOPHY(SNUBBING) 200




6.5.1 Containment Devices in the Workstring 200

6.5.2 Pump Down Plug and Nipple 203

6.5.3 Stabbing Valve 205

6.5.4 Full Opening Safety Valve 205

6.5.5 Inside BOP 205

6.5.6 Surface Lines and Manifolds 206

6.6 OPERATIONS 206 6.6.1 Opening the Well 207

6.6.2 Crossing the Balance Point 208

6.6.3 Pulling Out of Hole 209

6.6.4 Job Suspension 209

6.7 ESD SYSTEMS 209

6.8 DRY GAS WELLS 209

6.9 COMBINED WIRELINE/SNUBBING OPERATIONS 210 6.9.1 Contingencies 210


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SECTION ONE

Reasons for Well Intervention



1. REASONS FOR WELL INTERVENTIONS

1.1GENERAL

Many servicing operations can be conducted by rig workovers, however live well intervention is preferred since killing a well risks fluid invasion of the formation, thereby causing potential formation damage.

The primary objective of well intervention operations is the management of wells to provide optimum well production. This is achieved by conducting live well remedial operations, obtaining downhole reservoir data or preparation of the well for a dead well workover (if live well servicing cannot solve a problem). Occasionally, gathering of downhole reservoir data is a secondary objective when an intervention is planned for other reasons.

This data is usually to provide well information on lateral and vertical movement, current location of oil, water and gas and identifying the producing zones.

There are many reasons for remedial live well intervention well operations, most notably to:

• Remove obstructions to flow such as tubing blockage with sand, wax or asphalt.

• Eliminate excessive water or gas production.

• Repair mechanical failure.

• Improve production through well stimulation, re-completions or multiple completions on low productivity wells.

• Enhance production by conducting well stimulation such as hydraulic fractures on high productivity wells.

• Increase production by bringing other additional potentially productive zones on stream.

Before a well is entered, a complete analysis must be made of the current well status, the reasons for work carefully established, the associated risks identified and appropriate contingency measures planned in the event of operational failure.

All oil and gas wells will encounter some impairment to production during their producing life and well service operations need to be planned, either, to rectify or improve the conditions within the wellbore. Therefore, common servicing operations such as cleaning out fill, re-perforating, chemical treating, acidising, fracturing or a combination of these techniques are routinely carried out to enhance production.



1.1.1TUBING BLOCKAGETubing blockage is generally caused by sand, wax and asphalt production, or scale and can usually be remedied with a well clean out operation. Some of these problems can be prevented, or at least alleviated, by treating the formation with regular chemical inhibition treatments, pumped into the formation from surface.

Severe formation scaling can occur if injection water is not treated to be compatible with the formation fluids.

Tubing blockage is one of the most commonly experienced production problems and is remedied by clean out operations conducted by snubbing or coiled tubing (CT) intervention although dead well workover may also be considered. The use of snubbing or CT is more desirable as they can be carried out without killing the well. CT is preferred as it is relatively low cost, is easily organised and very effective when used in conjunction with modern jetting or clean-out tools (especially with the larger CT sizes which allow higher pump rates). In most circumstances, flowing the well helps with the efficiency of the clean out.

Wax build-up can be removed by ‘Hot Oiling’. This is a simple treatment consisting of pumping heated oil from surface at a temperature sufficiently high to melt the wax. This can also be done by circulation of hot oil through CT, which is preferred, as it prevents any fluids being pumped to the formation. Asphalt can also be removed in a similar manner by pumping solvents rather than hot oil.

Some well clean outs may be accomplished with wireline methods using tools such as gauge cutters which can remove wax from tubing walls and bailing to remove sand or other blockages, provided the amount to be removed is relatively small. It is often easier to use wireline, even if it may be less efficient, as many platforms are already equipped with permanent wireline units or they can be easily mobilised. CT takes longer to rig up and deploy which are considerations that need to be taken into account during the evaluation process. However in general, most operations can more efficiently be accomplished using CT and it is sometimes the only option if the well is high angle or horizontal. The general limit for wireline operations is circa 70° from vertical but this may vary according to well build up angles and the types of tools to be run.

Hydraulic Work Over units (HWO) may also be considered but they are generally slower and therefore more costly in comparison to CT. However, in some circumstances, e.g. where there is not enough space for a CT injector or the reel due to the size of the rig or where large size pipe is required for work on horizontal wells, Hydraulic Work Over may be the alternative.



1.1.2EXCESSIVE WATER OR GAS PRODUCTION As an oil zone is depleted, the gas/oil or water/oil interfaces will move vertically in the formation. This may result in increasing undesired water or gas production.

Excessive gas production leads to a premature decrease in reservoir pressure, hence reducing the energy available to move the oil into the well bore and ultimately reducing the quantity of gas necessary to lift the oil to surface.

When excessive water is produced, it leads to reduced oil production due to the increased hydrostatic head in the tubing acting against the formation pressure, increased risk of corrosion and production problems in handling and disposing of the water. It may also cause sand production that can lead to erosion of completion and production equipment.

These problems can be controlled by the appropriate well intervention measures, as described below.Control of Water ProductionThere are different reasons for water problems:

• Fingering of water in stratified or layered reservoirs where the water production is essentially from one zone.

• Advancing water level due to oil depletion.

• Water coning in reservoirs where there is appreciable vertical permeability

When a rock becomes saturated with water, the relatively permeability to water increases in regard to that of the other fluids. This leads to a self-aggravating cycle of increasing water flow.

Prior to running or planning operations for water control, production logs must be run to identify the zones from which water is being produced. Once identified, this can usually be controlled by a number of different methods depending on the specific well design and well conditions:

• Sand placement in the sump

• Setting a through tubing bridge plug

• Cement squeezing

• Chemical treatment to produce a gel block.

Sand placement in the sump may solve the problem in circumstances where there is sufficient height of sand and the vertical permeability of the column of sand is high and blocks water flow.

Cement squeezes have probably been the commonest means of plugging off water producing zones in the past utilising workover methods requiring the well to be killed, the completion to be pulled before cementing and re-completing.



High production liner or mono-bore type completions have been specifically designed for through tubing operations enabling water control by simply installing a through tubing bridge plug by wireline or CT after which cement can be squeezed, if necessary

Cement squeezing by CT below regular packer style completions using modern through tubing tooling, is now also common practice.

Water blocking by creating a gel at the formation is a much more recent development. This involves pumping chemicals to the formation, which react after a period of time to form a gel. The viscosity of the gel is so high that it remains in the formation pores, blocking the flow of water trapped behind the gel. This method is usually expensive due to high chemical costs.

Plugging back water producing zones may on occasions require the well to be re-completed if the packer has to be moved or if shallower zones need to be perforated and brought on stream.



Water Fingering Due to Heterogeneity’s

Advancing Oil/Water Contact



Water Production by Coning



1.1.3CONTROL OF GAS PRODUCTIONThe most common reason for excessive gas production is the growth of the gas cap as oil is produced. The gas/oil contact will gradually move downward causing an increase in the production of gas.

The common method of remedying excessive gas coning is to squeeze the gas producing zone and deepen the well by re-perforating (converse to water coning). An alternative is to conduct a workover where the well is plugged back and side-tracked with the new hole drilled horizontally through the lower part of the reservoir avoiding the gas cap.

In a layered reservoir, gas producing zones can also usually be effectively squeezed off with cement.

Increasing Gas Cap during Oil Production



1.1.4MECHANICAL FAILUREWell service operations to repair mechanical completion failures are still relatively common in old wells, however in new wells less servicing is required due to the increasing reliability of modern completion equipment.

In the past, one of the most common reasons for working over a well was to replace downhole safety valves that had failed. For this reason, engineers were inclined to install wireline retrievable valves as they could easily be replaced using live well interventions by wireline methods, hence avoiding the need to pull tubing. Nowadays, this is no longer the case as the reliability of tubing retrievable valves has increased substantially and it is now the most commonly used valve.

Probably the most common reason for remedial mechanical operations today is tubing failure due to erosion or corrosion.

Some completion failures can be repaired by wireline or CT methods but, in some circumstances, a full workover programme to pull the tubing is necessary.

Typical failures are:

• Downhole safety valve mechanical failure or leak.

• Casing, packer or tubing leaks.

• Casing collapse.

• Tubing collapse.

• Cement failure.

• Gas lift failure or inefficiency.

• ESP or hydraulic pump failure.

• Recovery of a fish unable to be recovered by intervention methods.

A full workover programme usually entails the placement of an overbalanced fluid against the formation unless it can be isolated using a plug, e.g. a Wireline plug in a permanent packer tailpipe or setting a through tubing plug in the casing above the producing zone(s).



1.1.5STIMULATION OF LOW PRODUCTION WELLSThere are many reasons why a well may have low productivity, such as:

• Formation damage

• Low permeability

• Pressure depletion

• Liquid hold up in a gas well

• Gas slip in an oil well

• Sand or other fill or debris

• Excessive water or gas production

• Mechanical failure

• Artificial lift failure

Reservoir problems such as formation damage and low permeability can sometimes be improved by stimulation operations such as acidisation or hydraulic fracturing.

In oil or gas wells where there is liquid hold up or gas slip; this is often countered by installing smaller diameter velocity strings. These may be coiled tubing strings installed inside the original completion by large size CT units. This tubing reaches down into the sump and provides a smaller flow area to improve liquid lift. These reeled strings are normally 2 3/8 inch, 2 7/8

inch or 3 1/2 inch OD and are run and hung off on a wireline lock or similar device.

The tubing is snubbed into the well by normal CT methods from large reels after a lock mandrel has been attached to the coil and RIH to setting depth.

The main disadvantage with this solution is the high weight of such large reels, which is often above the lifting capacity of some offshore installations. Smaller, more manageable, reel sizes involve more connections to make up offshore. These problems, however, are outweighed when set against the costs of a full re-completion programme.

An artificial lift system is usually required in any low permeability well to give adequate production rates. A work programme to re-complete this type of well is required once the well flow has reached the minimum economic acceptable natural flow. If the well has already been on gas lift and it is no longer efficient, then the gas lift design should be reviewed to optimise the existing gas lift completion.



1.1.6PARTIALLY DEPLETED RESERVOIRSIn a depleted oil reservoir, an effective artificial lift system can be installed to increase production. If a well was originally planned and designed for gas lift and completed with gas lift mandrels in the string then the gas lift valves are simply installed by wireline intervention. However, if a re-completion is needed, a full dead well workover would be necessary. In high angle wells, gas lift valves can be installed by coiled tubing methods.

Improved recovery by reservoir pressure maintenance is usually the best long-term approach to increased production rates.

1.1.7SAND CONTROLThere are normally two solutions for controlling unconsolidated sand

• gravel pack

• install a pre-packed screen ( resins are occasionally used )

The drawback of having to implement such control measures is that they reduce productivity typically by 10% to 15%.

The installation of a gravel pack involves a full workover and re-completion although new methods using HWO unit have been developed.

For a successful gravel pack it is important to ensure that clean fluids (containing little or no dispersal solids) are used on initial completion or when the gravel pack is installed. A second requirement is that the gravel is correctly sized in relationship to the formation sand to prevent further ingress or blind off. It also is desirable, if completing in a sand zone that is known to be unconsolidated, that the gravel pack is installed immediately, as it is more difficult to install at a later stage.

If an Open Hole (external) gravel pack is required the hole will need to be enlarged to about twice its size by under-reaming first before the liner/screen is run. Properly sized gravel is placed outside the screen by reverse circulation techniques. External gravel packs are utilised when high production rates are required. Internal gravel cause reduced production rates.

The use of pre-packed screens has increased in recent years as they can often be installed in an existing completed well avoiding re-completion; however they are more prone to blinding off as they do not provide the same effectiveness as a regular gravel pack in controlling the production of fines.


Documents

Iwcf Section One