Eni Completion Design Manual (Petroleum,Oil,Gas)

ARPO

ENI S.p.A. Agip Division

ORGANISING DEPARTMENT

TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REFER TO SECTION N.

PAGE.

OF

STAP

P

1

M

1

295

7100

TITLE COMPLETION DESIGN MANUAL

DISTRIBUTION LIST Eni - Agip Division Italian Districts Eni - Agip Division Affiliated Companies Eni - Agip Division Headquarter Drilling & Completion Units STAP Archive Eni - Agip Division Headquarter Subsurface Geology Units Eni - Agip Division Headquarter Reservoir Units Eni - Agip Division Headquarter Coordination Units for Italian Activities Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and a CD-Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni - Agip Division Headquarter) Date of issue:

28/06/99

f e d c b

Issued by

REVISIONS

M. Bassanini 28/06/99

C. Lanzetta 28/06/99

A. Galletta 28/06/99

PREP'D

CHK'D

APPR'D

The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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INDEX 1.

2.

3.

INTRODUCTION

8

1.1.

PURPOSE OF THE MANUAL

8

1.2.

OBJECTIVES

12

1.3.

FUNCTIONS OF A COMPLETION

13

1.4.

MANUAL UPDATING, AMENDMENT, CONTROL & DEROGATION

13

RESERVOIR CONSIDERATIONS

14

2.1.

INTRODUCTION

14

2.2.

CHARACTERISTICS OF RESERVOIR ROCKS 2.2.1. Porosity 2.2.2. Permeability 2.2.3. Relative Permeability 2.2.4. Wettabilty 2.2.5. Fluid Distribution 2.2.6. Fluid Flow In The Reservoir 2.2.7. Effects Of Reservoir Characteristics 2.2.8. Reservoir Homogeneity

14 14 14 15 16 17 18 24 27

2.3.

HYDROCARBON DATA 2.3.1. Oil Property Correlation

28 28

2.4.

RESERVOIR/PRODUCTION FORECAST 2.4.1. Inflow Perfomance 2.4.2. Reservoir Simulation For IPR Curves 2.4.3. IPR Selection 2.4.4. Outflow Performance 2.4.5. Flow Rate Prediction

29 31 42 44 46 55

WELL TESTING

60

3.1.

INTRODUCTION 3.1.1. Types of Tests

60 60

3.2.

DST OBJECTIVE

63

3.3.

DST STRING

64

3.4.

RESERVOIR CHARACTERISTICS 3.4.1. Pressure Build-Up Analysis 3.4.2. Basics Of DST Operations 3.4.3. Common Test Tools Description 3.4.4. Tools Utilised With Permanent Packer Systems 3.4.5. Sub-Sea Test Tools Used On Semi-Submersibles 3.4.6. Deep Water Tools 3.4.7. Downhole Pressure Recording

69 69 77 77 80 80 81 82

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3.5.

4.

5.

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WELL PRODUCTION TEST OBJECTIVES 3.5.1. Periodic Tests 3.5.2. Productivity Or Deliverability Tests 3.5.3. Transient Tests

0 83 83 84 84

DRILLING CONSIDERATIONS

87

4.1.

CASING DESIGN 4.1.1. Casing Profile 4.1.2. Casing Specifications 4.1.3. Casing Connections

87 87 88 89

4.2.

WELL DEVIATION SURVEYS

89

4.3.

CASING CEMENTING CONSIDERATIONS 4.3.1. Production Casing Cementing 4.3.2. Production Casing Cement Evaluation

90 90 91

WELL COMPLETION DESIGN

92

5.1.

FACTORS INFLUENCING COMPLETION DESIGN 5.1.1. Reservoir Considerations 5.1.2. Mechanical Considerations 5.1.3. Safety Considerations

94 94 96 96

5.2.

RESERVOIR-WELLBORE INTERFACE 5.2.1. Open Hole Completions 5.2.2. Uncemented Liner Completions 5.2.3. Perforated Completions 5.2.4. Multi-Zone Completions

97 97 98 100 101

5.3.

CASING-TUBING INTERFACE 5.3.1. Packer Applications 5.3.2. Packer-Tubing Interfaces 5.3.3. Annulus Circulation

104 106 107 108

5.4.

TUBING-WELLHEAD INTERFACE 5.4.1. Tubing Hanger Systems 5.4.2. Xmas Trees 5.4.3. Metal-To-Metal Seals

109 109 115 115

5.5.

FUTURE CONSIDERATIONS 5.5.1. Stimulation 5.5.2. Formation Management 5.5.3. Well Servicing Techniques

117 118 118 119

5.6.

OPTIMISING TUBING SIZE 5.6.1. Reservoir Pressure 5.6.2. Flowing Wellhead Pressure 5.6.3. Gas-Liquid Ratio 5.6.4. Artificial Lift

121 123 123 123 124

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7.

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CORROSION

0

126

6.1.

DEVELOPMENT WELLS

126

6.2.

CONTRIBUTING FACTORS TO CORROSION

126

6.3.

FORMS OF CORROSION 6.3.1. Sulphide Stress Cracking (SSC) 6.3.2. Corrosion Caused By CO2 And Cl 6.3.3. Corrosion Caused By H2S, CO2 And Cl-

128 128 135 137

6.4.

CORROSION CONTROL MEASURES

138

6.5.

CORROSION INHIBITORS

139

6.6.

CORROSION RESISTANCE OF STAINLESS STEELS 6.6.1. Martensitic Stainless Steels 6.6.2. Ferritic Stainless Steels 6.6.3. Austenitic Stainless Steels 6.6.4. Precipitation Hardening Stainless Steels 6.6.5. Duplex Stainless Steel

139 139 140 140 140 142

6.7.

COMPANY DESIGN PROCEDURE 6.7.1. CO2 Corrosion 6.7.2. H2S Corrosion

142 142 142

6.8.

MATERIAL SELECTION 6.8.1. OCTG Specifications 6.8.2. DHE Specifications 6.8.3. Wellhead Specifications

144 145 146 147

6.9.

ORDERING SPECIFICATIONS

152

TUBING DESIGN

153

7.1.

POLICIES

153

7.2.

THEORY 7.2.1. Mechanical Properties of Steel 7.2.2. Temperature 7.2.3. Tubing Movement/Stress Relationship

153 154 158 158

7.3.

WELL DATA. 7.3.1. Casing Profile/Geometry 7.3.2. Tubing Data 7.3.3. Bottom-hole Pressure 7.3.4. Temperatures (Static and Flowing) 7.3.5. Reservoir Fluids 7.3.6. Completion Fluid

160 160 160 160 160 161 161

7.4.

PRESSURE INDUCED FORCES 7.4.1. Piston Effect 7.4.2. Buckling Effect 7.4.3. Ballooning Effect 7.4.4. Temperature Effect

161 162 163 167 168

7.5.

EVALUATION OF TOTAL TUBING MOVEMENT

169

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7.6. ANCHORED TUBING 7.6.1. Tubing Permitting Limited Motion 7.6.2. Packer Setting

170 172 174

7.7.

TUBING LOAD CONDITIONS 7.7.1. Pressure Testing 7.7.2. Acid Stimulation 7.7.3. Fracturing 7.7.4. Flowing 7.7.5. Shut-In 7.7.6. Load Condition Summary

174 174 175 175 177 177 181

7.8.

TUBING SELECTION 7.8.1. Critical Factors 7.8.2. Tubing Size And Weight 7.8.3. Anchoring Systems

181 182 182 184

7.9.

TUBING CONNECTIONS 7.9.1. Policy 7.9.2. Class of Service 7.9.3. Selection Criteria 7.9.4. NACE And Proximity Definitions 7.9.5. CRA Connections 7.9.6. Connection Data

185 185 185 186 189 190 190

7.10. TUBING STRESS CALCULATIONS 7.10.1. Calculation Methods 7.10.2. Safety Factor 7.10.3. External Pressure Limit 7.10.4. Packer Load Limits 7.10.5. Example Manual Calculation 7.10.6. Example Computation

8.

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SUB-SURFACE EQUIPMENT

190 191 193 195 195 196 205

206

8.1.

PACKERS 8.1.1. Selection Procedure 8.1.2. Selection Criteria 8.1.3. Well Classification 8.1.4. Packer Selection For Single String Completion 8.1.5. Single Selective Completion Packers

206 207 207 209 209 217

8.2.

SUB-SURFACE SAFETY VALVES 8.2.1. Policy 8.2.2. Applications 8.2.3. Wireline Retrievable Safety Valves 8.2.4. Surface Controlled Sub-Surface Safety Valves 8.2.5. Valve Type/Closure Mechanism Selection

223 223 223 223 224 224

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8.3.

CONTROL/INJECTION LINE SELECTION 8.3.1. Control Lines 8.3.2. Injection Lines 8.3.3. Tube Specifications 8.3.4. Material Selection 8.3.5. Fittings 8.3.6. Protectors 8.3.7. Encapsulation 8.3.8. SCSSV Hydraulic Control fluid 8.3.9. Control/Injection Line Selection Procedure Flow Chart

225 225 225 226 228 230 230 231 233 236

8.4.

WIRELINE NIPPLE SELECTION 8.4.1. Tapered Nipple Configuration 8.4.2. Selective Nipple Configuration

237 238 239

PERFORATING

240

9.1.

SHAPED CHARGE PERFORATING

240

9.2.

GUN TYPES 9.2.1. Wireline Conveyed Casing Guns 9.2.2. Through-Tubing Hollow Carrier Guns 9.2.3. Through-Tubing Strip Guns 9.2.4. Tubing Conveyed Perforating

241 241 243 243 243

9.3.

GUN PERFORMANCE 9.3.1. API And Performance Data 9.3.2. Underbalanced Perforating 9.3.3. Firing Heads 9.3.4. Perforating Procedures

244 244 246 247 247

10. ARTIFICIAL LIFT

250

10.1. GAS LIFT 10.1.1. Impact On Completion Design 10.1.2. Common Problems

251 253 254

10.2. ELECTRICAL SUBMERISBLE PUMPS 10.2.1. ESP Performance 10.2.2. Impact On Completion Design 10.2.3. Common Problems

254 256 259 259

10.3. HYDRAULIC PUMPING SYSTEMS 10.3.1. Impact On Completion Design

260 262

10.4. ROD PUMPS 10.4.1. Impact On Completion Design

262 265

10.5. SCREW PUMP SYSTEMS

265

10.6. PLUNGER LIFT

265

10.7. SUMMARY ARTIFICIAL LIFT SELECTION CHARTS 10.7.1. Design Considerations And Comparisons 10.7.2. Operating Conditions Summary 10.7.3. Artificial Lift Considerations

268 268 270 272

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11. USE OF UNDERBALANCE COMPLETION FLUIDS

274

11.1. POLICY

274

11.2. BARRIER PRINCIPLES

274

11.3. APPLICATION

274

11.4. RISK ASSESSMENT 11.4.1. Well Testing 11.4.2. Completions

275 275 275

APPENDIX A - REPORT FORMS

276

A.1.

INITIAL ACTIVITY REPORT (ARPO 01)

277

A.2.

DAILY REPORT (ARPO 02)

278

A.3.

WASTE DISPOSAL MANAGEMENT REPORT (ARPO 06)

279

A.3.

PERFORATING REPORT (ARPO 07)

280

A.4.

GRAVEL PACK REPORT (ARPO 08)

281

A.5.

MATRIX STIMULATION/HYDRAULIC FRACTURE REPORT (APRO 09)

282

A.6.

WIRELINE REPORT (ARPO 11)

283

A.7.

PRESSURE/TEMPERATURE SURVEY REPORT (ARPO 12)

284

A.8.

WELL PROBLEM REPORT (ARPO 13)

285

A.9.

WELL SITUATION REPORT (ARPO 20)

286

APPENDIX B - NOMENCLATURE FOR TUBING CALCULATIONS

287

APPENDIX C - ABBREVIATIONS

289

APPENDIX D - BIBLIOGRAPHY

292

APPENDIX E - TUBING MOVEMENT/STRESS COMPUTER PROGRAMMES

294

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1.

INTRODUCTION

1.1.

PURPOSE OF THE MANUAL

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The purpose of this manual is to guide experienced engineers of all technical disciplines, within the Eni-Agip Division and Affiliated Companies, in the completion design process and its importance on well productivity, well servicing capabilities and completion life. These in consequence, have a large impact on costs and field profit. The Corporate Standards in this manual define the requirements, methodologies and rules that enable to operate uniformly and in compliance with the Corporate Company Principles. This, however, still enables each individual Affiliated Company the capability to operate according to local laws or particular environmental situations. The final aim is to improve performance and efficiency in terms of safety, quality and costs, while providing all personnel involved in Drilling & Completion activities with common guidelines in all areas worldwide where Eni-Agip operates. The approach to completion design must be interdiscipline, involving Reservoir Engineering, Petroleum Engineering, Production Engineering and Drilling Engineering. This is vital in order to obtain the optimum completion design utilising the process described in this manual. The manual will provide the engineers within the various disciplines with a system to guide them through the process with the objectives of helping them make the key decisions and obtaining the optimum design to maximise productivity and, hence profit. Many of the decisions made by the various disciplines are interrelated and impact on the decisions made by other disciplines. For instance, the decision on the well architecture may subsequently be changed due to the availability of well servicing or workover techniques. This does not mean that the process is sequential and many decisions can be made from studies and analysis run in parallel. The design process consists of three phases: • • •

Conceptual Detailed design Procurement.

The process of well preparation and installation of completions is fully described in the ‘Completions Procedures manual’. The activities in each phase are illustrated in figure 1.a, figure 1.b and figure 1.c. The conceptual design process guides the engineers through analysis and key questions to be considered. During this phase, the user will resolve many of the dilemmas, raised by the interrelated decisions, at an early time. The final conceptual design will be used as the basis for the detailed design process. The conceptual design process begins at the field appraisal stage when a Statement Of Requirements (SOR) of the completion is produced. It is essential that this is an accurate statement including all the foreseen requirements, as it has a fundamental effect on the field final design and development.

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As more information is gleamed from further development wells and as conditions change, the statement of requirements need to reviewed and altered to modify the conceptual design for future wells. This provides a system of ongoing completion optimisation to suit changing conditions, increased knowledge of the field and incorporate new technologies.

Figure 1.A - Conceptual Completion Design Process

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Figure 1.B - Detailed Completion Design Process

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Figure 1.C - Procurement Process

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OBJECTIVES The fundamental objectives for a completion are: • • • • • • •

Achieve a desired (optimum) level of production or injection. Provide adequate maintenance and surveillance programmes. Be as simple as possible to increase reliability. Provide adequate safety in accordance with legislative or company requirements and industry common practices. Be as flexible as possible for future operational changes in well function. In conjunction with other wells, effectively contribute to the whole development plan reservoir plan. Achieve the optimum production rates reliably at the lowest capital and operating costs.

These may be summarised as to safely provide maximum long term profitability. This, however, in reality is not simple and many critical decisions are needed to balance long term and short term cash flow and sometimes compromises are made. An expensive completion may derive more long term profit than a low cost completion but the initial capital costs will be higher (Refer to figure 1.d).

Figure 1.D - Completion Design Versus Profitability

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On the other hand if the data available is not accurate, the estimate of some well performance and characteristics throughout the life of the well may be wrong and early workover or well intervention operations will impact on well profitability. An inherent problem is that the Reservoir Engineering Department’s objectives do not coincide with the Completion Engineering Department’s in that Reservoir Engineering’s objectives are for the whole field performance whereas the Completion Group’s is to optimise for profit on a long term well by well basis which includes well servicing/workover. Reservoir and geoscience groups often have to set plans and objectives for the field on well performance based on limited information, in the early stages, but are not concerned about production problems, well maintenance or detailed operations. 1.3.

FUNCTIONS OF A COMPLETION The main function of a completion is to produce hydrocarbons to surface or deliver injection fluids to formations. This is its primary function, however a completion must also satisfy a great many other functions required for safety, optimising production, servicing, pressure monitoring and reservoir maintenance. These main functional requirements must be built into the conceptual design and include: • • • • • • •

1.4.

Protecting the production casing from formation pressure. Protecting the casing from corrosion attack by well fluids. Preventing hydrocarbon escape if there is a surface leak. Inhibiting scale or corrosion. Producing single or multiple zones. Perforating (underbalanced or overbalanced). Permanent downhole pressure monitoring.

MANUAL UPDATING, AMENDMENT, CONTROL & DEROGATION The Corporate Standards in this manual define the requirements, methodologies and rules that enable to operate uniformly and in compliance with the Corporate Company Principles. This, however, still enables each individual Affiliated Company the capability to operate according to local laws or particular environmental situations. The final aim is to improve performance and efficiency in terms of safety, quality and costs, while providing all personnel involved in Drilling & Completion activities with common guidelines in all areas worldwide where Eni-Agip operates.

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2.

RESERVOIR CONSIDERATIONS

2.1.

INTRODUCTION

0

Oil and gas wells are expensive faucets that enable production of petroleum reservoirs or allow injection of fluids into an oil or gas reservoir. As pointed out in section 1.1, a completion conceptual design must take into account all the well objectives to produce the optimum design to maximise profitability. The purpose of this section is to consider the characteristics of reservoir fluids and the flow of these in the area around the wellbore to allow these parameters to be tied into the well completion design and well intervention/workover operational requirements. 2.2.

CHARACTERISTICS OF RESERVOIR ROCKS

2.2.1.

Porosity Porosity or pore space in reservoir rocks provides the container for the accumulation of oil and gas and gives the rock characteristic ability to absorb and hold fluids. Most commercial reservoirs have sandstone, limestone or dolomite rocks, however some reservoirs even occur fractured shale.

2.2.2.

Permeability Permeability is a measure of the ability of which fluid can move through the interconnected pore spaces of the rock. Many rocks such as clays, shales, chalk, anhydrite and some highly cemented sandstones are impervious to movement of water, oil or gas even although they may be quite porous. Darcy, a French engineer, working with water filters, developed the first relationship which described the flow through porous rock which is still used today. Darcy’s Law states that the rate of flow through a given rock varies directly with permeability (measure of the continuity of inter-connected pore spaces) and the pressure applied, and varies inversely with the viscosity of the fluid flowing. In a rock having a permeability of 1 Darcy, 1cc of a 1cp viscosity fluid will flow each second 2 through a portion of rock 1cm in length and having a cross-section of 1cm , if the pressure across the rock is 1 atmosphere. K=

qµL A∆p

Eq. 2.A

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In oilfield units the linear form of Darcy’s Law for flow of incompressible fluid through a rock filled with only one fluid is: q=1.127 ×10 −3

kA(p 1 −p 2 ) BµL

Eq. 2.B

where: q k A µ L p1 p2 B 2.2.3.

= = = = = = = =

Flow rate, stb/day Permeability, md 3 Flow rate, ft Viscosity, cp Flow length, ft Inlet pressure, psi Outlet pressure, psi Formation volume factor, res bbl/stb

Relative Permeability As normally two or three fluids exist in the same pore spaces in a reservoir, relative permeability relationships must be considered. Relative permeability represents the ease at which one fluid flows through connecting pore spaces in the presence of other fluids, in comparison to the ease that it would flow if there was no other fluid. To understand this, assume a rock filled with only with oil at high pressure where gas has not been able to come out of solution: • • • • •

All available space is taken up by the oil and only oil is flowing. If reservoir pressure is allowed to decline, some lighter components of the oil will evolve as gas in the pore spaces. Flow of oil is reduced but gas saturation is too small for it to flow through the pores. If pressures to continue to decline, gas saturation continues to increase and at some point (equilibrium gas saturation) gas begins to flow and the oil rate is further reduced. With further increases in gas saturation, the gas rate continues to increase and less oil flows through the pores until finally only gas flows. Significant oil may still occupy the pores but cannot be recovered by primary production means as the permeability to oil has dropped to zero.

This same principle governs the flow of oil in the presence of water. The saturation of each fluid present affects the ease of fluid movement or relative permeability. The gas-oil or water-oil relative permeability relationships of a particular reservoir rock depend on the configurations of the rock pore spaces and the wetting characteristics of the fluids and rock surfaces. In an oil-water system, the relative permeability to oil is significantly greater when the rock is ‘water wet’.

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Where two or more fluids are present, the permeability in eq. 2.b represents the permeability of the rock to the desired fluid. This can be achieved by multiplying absolute permeability of the rock by the relative permeability of the rock to the desired fluid. q=1.127 ×10 −3

k abs k ro A(p1 −p 2 ) B o µL

Eq. 2.C

where: qo kabs kro

= = =

Oil flow rate, stb/day Absolute permeability, md Relative permeability to oil

For a well producing both water and oil, the ‘water cut’ or fraction of water in the total flow stream at standard conditions of temperature and pressure can be calculated by: fw =

1 k o µw Bw 1× + + k w µo Bo

Eq. 2.D

where: ko kw µo µw Bo Bw 2.2.4.

= = = = = =

Relative permeability to oil Relative permeability to water Viscosity of oil, cp Viscosity of water, cp Formation volume factor for oil, res bbl/stb Formation volume factor for water, res bbl/stb

Wettabilty Most reservoirs were formed or laid down in water with oil moving in later from adjacent zones to replace a portion of the water. For this reason, most reservoir rocks are considered to be ‘water wet’. This means that the grains of the rock matrix are coated with a film of water permitting hydrocarbons to fill the centre of the pore spaces. The productivity of oil in this condition is maximised. Although it is extremely difficult to determine wettability of cores due to the cutting and preparing specimens for laboratory testing which alters the wettability characteristics, it is not important as this characteristic is included in the permeability measurements. However, it is important when completing or servicing the well in that any foreign substance which may come into contact with the rock may alter its wettability characteristic and reduce the relative permeability to hydrocarbon fluids and cause emulsion which may block flow.

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Fluid Distribution The distribution of fluids vertically in the reservoir is very important as the relative amounts of oil, gas and water present at a particular level determines the fluids that produced by a well completed at that level and also influence the relative rates of fluid production. In rock the capillary forces, which are related to water wettability, work to change the normal sharp interfaces between the fluids separated by density. From the point in a zone of the free water level upward to some point where water saturation becomes constant is called the ‘transition zone’. Relative permeability permits both water and oil to flow within the transition zone. Water saturation above the transition zone is termed ‘irreducible water saturation’ or more commonly the ‘connate water saturation’. Above the transition zone, only oil will flow in an oil-water system. Connate water is related to permeability and pore channels in lower rocks are generally smaller. For a given height, the capillary pressure in two different pore sizes will be the same, therefore the water film between the water and the oil will have the same curvature, hence more oil will be contained in larger pore spaces. The nature and thickness of the transition zones between the water and oil, oil and gas, and water and gas are influenced by several factors: uniformity, permeability, wettability, surface tension and the relative density differences between the fluids. These can be summarised in three statements: • • •

The lower the permeability of a given sand, the higher will be the connate water saturation. In lower permeability sands, the transition zones will be thicker than in higher permeability sands. Due to the greater density difference between gas and oil as compared to oil and water, the transition zone between the oil and gas is not as thick as the transition zone between oil and water.

A well completed in the transition zone will be expected to produce both oil and water, depending on the saturations of each fluid present at the completion level. figure 2.a summarises oil, water and gas saturation in a typical homogeneous rock example.

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Figure 2.A - Example Fluid Distribution in a Uniform Sand Reservoir (Containing Connate Water, Oil and Gas Cap) 2.2.6.

Fluid Flow In The Reservoir Oil has little natural ability to produce itself into the wellbore. It is produced principally by pressure inherent in gas dissolved in oil, in associated free gas caps, or in associated aquifers. Pressure Distribution Around the Wellbore Pressure distribution in the reservoir and factors which influence it are of great of significance in interpreting well production trends caused by pressure characteristics. Pressure distribution around a producing oil well completed in a homogeneous zone will gradually drop from the reservoir pressure some distance from the wellbore until closer to the wellbore where it will decline quite sharply. The wellhead pressure will be much lower due to the influence of hydrostatic pressure and tubing frictional effects.

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In a radial flow situation, where fluids move towards the well from all directions, most of the pressure drop in the reservoir occurs fairly close to the wellbore. As shown in figure 2.b, in a uniform sand, the pressure drop across the last 15ft of the formation surrounding the wellbore is about one half of the total pressure drop from the well to a point 500ft away in the reservoir. Obviously flow velocities increase tremendously as fluid approaches the wellbore. This area around the wellbore is the ‘critical area’ and as much as possible should be done to prevent damage or flow restrictions in this critical area.

Figure 2.B - Pressure Distribution Near Wellbore In Radial Flow Radial Flow Around The Wellbore Steady state radial flow of incompressible fluid is described by Darcy’s Law: q=

0.00708kh(p o −p w ) r Bµ1n( o ) rw

Eq. 2.E

Corrections are required to account for the flow of compressible fluids and for turbulent flow velocities.

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Figure 2.C- Units For Darcy’s Law Equation For non-homogeneous zones, which is the usual case, permeablities must be averaged for flow through parallel layers of differing permeabilities. k=

k 1h1 +k 2 h 2 +k 3 h 3 h1 +h 2 +h 3

Figure 2.D - Radial Flow In Parallel Combination of Beds

Eq. 2.F

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Varying permeabilities around the well in series can be averaged as follows: ro ) rw k= r r r 1n( 1 ) 1n( 2 ) 1n( 3 ) rw r1 r2 + + k1 k2 k3 1n(

Eq. 2.G

Figure 2.E - Radial Flow In Series Combination Of Beds Linear Flow Through Perforations Ideally perforating tunnels should provide be large and deep enough to prevent any restriction to flow. In cases where there may be sand problems and a gravel pack is used, the tunnels are packed with gravel to hold the formation in place, which will cause a restriction. Flow through perforating tunnels is linear rather radial and Darcy’s equation must be corrected as turbulent flow usually exists. Experiments have shown that pressure drop through gravel filled perforations compared with uncorrected linear flow Darcy’s Law calculations is substantial as shown in figure 2.f below. Curve A indicates that plugging with even high permeability (1 Darcy) sand gives a large pressure drop. Actual test data with very high permeability sand, curve B, proves turbulent flow results in higher pressure drop than Darcy’s Law calculations, curve C, predict. Investigators have provided turbulence correction factors which can be applied to Darcy’s equation to permit calculation of pressure drop through perforating tunnels.

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Figure 2.F - Pressure Drop Versus Flow Rate Through Perforation Causes Of Low Flowing Bottom-Hole Pressure In a well with uniform sand and fluid conditions, two factors may cause low flowing bottomhole pressures. These are permeability and producing rate. With low permeability or excessive rate of production, pressure drawdown will be appreciable higher than normal thus reducing flowing bottom-hole pressures and causing the well to be placed on artificial lift if higher productions rates are necessary. Low permeability is often caused by damage close to the wellbore through drilling, completion or intervention operations. This is particularly detrimental as the effect close to the wellbore is greatly magnified.

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The existence of damage can be calculated by well test results analysing the pressure build-up periods. The skin effect (abnormal pressure drop) or the normal radial flow pressure drop can be calculated by: ∆p s =

141.2qBµ ×s kh

Eq. 2.H

Other terms which are used to quantify formation damage are Damage Ratio and Flow Efficiency. Damage ratio calculation is: DR=

Eq. 2.I

qt qa

where: = =

qt qa

Theoretical flow rate without damage Actual flow rate observed

also: DR= =

Jideal Jactual

Eq. 2.J

p−p wf p−p wf −∆p s

Flow efficiency: FE= =

Jideal Jactual

Eq. 2.K

p−p wf −∆p s p−p wf

In multi-zone completion intervals, where transient pressure testing techniques may give questionable results concerning formation damage, production logging techniques may provide helpful data. Flow profiling may highlight zones, in an otherwise productive interval, which are not contributing to the total flow. Non-contributing zones are likely to have been damaged.

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Effects Of Reservoir Characteristics Reservoir Drive Mechanisms In an oil reservoir, primary production results from existing pressure in the reservoir. There are three basic drive mechanisms: • • •

Dissolved gas Gas cap Water drive.

Most reservoirs in actuality produce by a combination of all three mechanisms. In a dissolved gas reservoir, the source of pressure is principally the liberation and expansion of gas from the oil phase as pressure is reduced. A gas drive reservoir’s primary pressure source is the expansion of a gas cap over the oil zone. A water drive reservoir’s principle pressure source is an external water hydrostatic pressure communicated to below the oil zone. The effect of the drive mechanism on the producing characteristics must be evaluated in the completion design process, and also for later re-completions, to systematically recover reservoir hydrocarbons. figure 2.g and figure 2.h, show typical reservoir pressures versus production trends and gas-oil ratio production trends for the three basic drive mechanisms. In a dissolved gas drive reservoir without any artificial pressure maintenance technique, pressure declines rapidly, gas-oil ratio peaks rapidly and then declines rapidly, and primary oil recovery is relatively low. Re-completing would not reduce the gas-oil ratio. In a gas cap drive reservoir, pressure declines less rapidly and gas-oil ratios increase as the gas cap expands into the up-structure well completion intervals. Well intervention or recompletion to shut-off up-structure intervals may control the gas-oil ratio, therefore lose pressure less rapidly. Water drive reservoirs pressure remains high and gas-oil ratios are lower but downstructure well intervals quickly begin to produce water. This is controlled by well interventions or re-completions to shut-off the water production or the well is shut-in. Gradually even the up-structure wells will water out to maximise oil recovery. Obviously many factors must be considered in developing a reservoir, however the main factors concentrate on the reservoir itself and the procedure used to exploit hydrocarbon recovery. Well spacing, or well location, is fundamental and the cost of time, labour and materials consumed in the drilling are largely non-recoverable, therefore if development drilling proceeds on the basis of close spacing before the drive mechanism is identified, the investment will have already been made. This does not usually present an insurmountable problem as a field of any considerable size will require a minimum number of wells to be drilled in any case to define the reservoir, i.e. establish the detailed geological picture regarding zone continuity and locate oil-water and gas-oil contacts. By careful planning when enough information is gained to determine the well locations, these can be drilled at the appropriate spacing to maximise recovery with the least amount of wells.

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Many case histories are available to show problems resulting from reservoir development without having sufficient information about the stratigraphy of the reservoir.

Figure 2.G - Reservoir Pressure Trends For Various Drive Mechanisms

Figure 2.H - Gas-Oil Ratios Trends For Various Drive Mechanisms

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With regard to drive mechanisms, some general statements can be made: Dissolved gas drive reservoirs: Well completions in reservoirs with low structural relief can be made in a regularly spaced pattern throughout the reservoir and, provided the rock is stratified, can be set low in the reservoir bed. A regular spacing can also be used for dissolved gas reservoirs with high angle of dip. Again the completion intervals should be structurally low because of the angle of dip and the exact sub-surface location would vary with well location on the structure. In this scenario it would be expected that oil recovery would be greater with the minimum well investment as the oil will drain down-structure through time. If this is recognised after drilling begins, the well locations must be changed quickly to take full advantage of the situation. Due to the low recovery by the primary drive mechanism, some means of secondary recovery will almost certainly be required at some point in life of the reservoir and the initial well completion design should take this into account. Gas cap drive reservoirs: Wells are generally spaced on a regular pattern where the sand is thick, dip angle is low and gas cap is completely underlayed by oil. Again completion intervals should be low in the structure to permit the gas cap to grow for maximum recovery and minimum gas production. Like the dissolved gas drive reservoir, the wells in thin sands with a high angle of dip is likely to be more efficiently controlled by having the completion irregularly spaced and low to conform to the shape of the reservoir. Regular spacing would place many completions too near the gas-oil contact. Such reservoirs are common where multiple this sands are found on a single structure and the oil column is only a fraction of the total productive relief. Water drive reservoirs: Wells can be spaced on a regular pattern on a thick sand and low angle of dip. Completion intervals should be selected high on the structure to permit long production life while oil is displaced up to the completion intervals by invading water from below. A water reservoir in a thin sand with high angle of dip may best be developed with irregular well spacing because of the structural characteristics. Regular spacing of the wells may cause early water production and possible early abandonment in conjunction with reducing the drive effectiveness through excessive water production. Significant levels of water production are unavoidable in later field life when maximising production rates.

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Reservoir Homogeneity The general procedures, as described in the previous section is to complete water drive reservoirs high and for dissolved gas drive reservoir low on the structure to obtain an adequate number of wells without excess. However this is only practical if the reservoir is uniform. Most sandstone reservoirs were originally laid down as stratified layers of varying porosity and permeability. Similar assumptions can be made for carbonate and even reef type reservoirs which results in reservoirs of a highly stratified nature. Fluids from such reservoirs will flow through the various layers at different restrictions to flow and often there are impervious beds between the layers so that fluid cannot flow between the bed to bed. This is demonstrated in figure 2.i and figure 2.j. In thin beds or highly stratified beds, ‘fingering’ of the free gas down from a gas cap, or water from a water basin, is a distinct possibility, especially if the interval is short and production rates are high. If the reservoir is stratified, either by shale breaks or by variations in permeability, it will probably be necessary to stagger the completion intervals in various members of the reservoir to be sure that each is drained properly. Vertical staggering of the completion can be effected during development to obtain proportionate depletion of the various strata. Additional distribution of intervals in the various members can then be made during later well interventions on the basis of data obtained, experience and operating conditions. To maximise recovery, intervals should be produced independently wherever practical (usually determined by economics). Single string/single zone completions are preferred to facilitate thorough flushing for higher recovery and flexibility of re-completion to control reservoir performance. Completions with more than one zone are termed multi-zone completions and are required for long completion intervals for obtaining sufficient volumes of production.

Figure 2.I - Irregular Water Encroachment and Breakthrough

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Figure 2.J - High GOR Production by Encroachment of Gas 2.3.

HYDROCARBON DATA The practical approach to the study of reservoir fluid behaviour is to anticipate pressure and temperature changes in the reservoir and at surface during production, and to measure, by laboratory tests, the changes occurring in the reservoir samples. The results of these tests then provide the basic fluid data for estimates of fluid recovery by various methods of reservoir operations and also to estimate reservoir parameters through transient pressure testing. Two general methods are used to obtain samples of reservoir oil for laboratory examination purposes, by means of subsurface samplers and by obtaining surface samples of separator liquid and gas. The surface samples are then recombined in the laboratory in proportions equal the gas-oil ratio measured at the separator during well testing. Information concerning the characteristics and behaviour of gas needed for gas reservoirs, depends upon the type of gas and the nature of the problem. If retrograde condensation is involved, it may require numerous tests and measurements. If the gas is wet with no retrograde condensation, or if dry gas, the information is less complex.

2.3.1.

Oil Property Correlation Several generalisations of oil sample data are available to permit correlations of oil properties to be made (refer to the Compant Well Test Manual for sampling techniques).

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RESERVOIR/PRODUCTION FORECAST To obtain the optimum performance from a well, it is first necessary to determine its full potential and which way this can be fully exploited within any technical or economic constraints. The determination of the well’s performance entails analysing the following: • • • •

In-flow performance Near wellbore performance and design Multiphase flow of tubing performance Artificial lift.

The process of this analysis is shown in figure 2.k which requires continuous repetition during field life to account for changing conditions. The inflow performance relationship (IPR) provides the flow potential of the reservoir into the wellbore against the resistance to flow of the formation and near wellbore region. The theoretical IPR is an idealistic assumption of flow performance without pressure drop due to skin effect in the near wellbore region and governed only by the size, shape and permeability of the producing zone and the properties of the produced fluids. The basic theory of this is described in this section along with some simplified IPR relationships from observed field data. Flow behaviour in the near wellbore region may cause a dramatic effect on the IPR curve which results in greatly reduced flow capability. This is characterised by a damaged IPR curve and the amount of damage or skin effect, is mainly caused by the drilling and completion practices. Good drilling and completion practices can or may minimise this damage allowing use of the idealised IPR curve to be used for completion design. Some completion designs to deal with reservoir conditions, such as gravel packs for unconsolidated sands, will also cause reduced IPR curves which must be anticipated during the design phase. Two phase flow, velocity effects in gas wells, high rate or high GOR oil wells, in undamaged near wellbore regions also reduce the IPR curve. Alternatively, stimulation procedures which can provide a negative skin are desirable as this increases production. Once the IPR is completed, the outflow performance can be determined which takes into consideration the relationship between the surface flowrate and pressure drop in the tubing. The prediction of this relationship is complicated by the nature of multi-phase fluid flow. Hence, analysis of the outflow performance requires predictions of phase behaviour, effective fluid density, friction losses and flowing temperatures. The results of the outflow performance analysis are usually produced graphically depicting how bottom hole flowing pressure (BHFP), or pump intake pressure, varies with flowrate against a fixed back-pressure which is normally the wellhead or separator pressure. These curves are termed tubing performance curves (TPC) and the point of intersection is the natural flowing point as demonstrated earlier in figure 2.k.

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Figure 2.K - Process of Determining Optimum Well Performance Selecting, or optimising, the tubing size is necessary to optimise the well performance over the life of the well and should include the potential benefits of artificial lift systems and/or stimulation to reduce near wellbore skin effects.

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Inflow Perfomance This section addresses the fundamental principles of inflow performance for oil and gas wells. The use of IPRs generated from reservoir simulation models is also described as is the technique for the applications of the various techniques for predicting inflow performance. Essentially the less data which is available, the more appropriate it is to use theoretical radial flow equation. As more data becomes available, an empirical expression can be validated and applied, however for larger projects, reservoir simulation is usually employed. Oil Well - Straight Line IPR The simplest IPR equation assumes that inflow into a well is proportional to the pressure differential between the reservoir and the wellbore which is termed the ‘drawdown’. ∆p=p R −p wf

Eq. 2.L

where: ∆p pR pwf

= = =

Drawdown pressure, psi Reservoir pressure, psi Bottom-hole flowing pressure, psi.

With a straight line IPR, the flow rate is directionally proportional to the drawdown. The linear relationship can be substantiated from theoretical arguments for a single incompressible fluid (i.e. above the bubble point). However, it has been verified that the straight line approach also provides the accuracy needed for well performance calculations in situations which exceed the theoretical basis, e.g. low drawdowns and damaged wells. In situations which allow the use of a straight line IPR, the constant of proportionality is termed the productivity index (PI). PI defined as J by the API, is: J=

q p R − p wf

Eq. 2.M

where: q

=

Total liquid flow rate at surface under stock tank conditions (14.7psia, o 60 F)

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Figure 2.L - Straight Line IPR or Productivity Index J The assumption of stable inflow performance relationship, or stabilised flow, is that well is producing in pseudo-steady state or steady state flow conditions. Before this the well produces under transient conditions, as in most well tests, result in higher estimates of productivity than when under stabilised conditions. Productivity Index, J, also needs to be treated with caution as Production Engineers and Reservoir Engineers assume different basis for J. Production Engineers relate J to gross liquid production (oil and water) whereas Reservoir Engineers relate it to oil productivity.

J can be calculated directly from bottom-hole gauges in well test results or estimated pressures from simulation studies. Oil PI, J, can also be derived theoretically from Darcy’s radial flow equation: Jo =

Eq. 2.N

k oh  r 141.2µ o B o 1n e   rw

  −0.75+S′  

where: h ko µo Bo ro rw S’

= = = = = =

Net pay thickness, ft Effective oil permeability, md Reservoir fluid viscosity, cp Reservoir formation volume factor, bbl/stb Drainage radius, ft Wellbore radius, ft Total effective skin, dimensionless (S ’= S + Dq)

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This assumes pseudo-steady state flow from a well in the centre of a circular reservoir and it is worth noting that ko is the effective permeability to oil for an oil PI. As water saturation increases, Ko obviously decreases and as does Jo. Deviation from the theoretical ideal PI (i.e. S’ = 0) should be expected as a result of additional pressure losses in the near wellbore area due to damage, fractures, increased gas saturation in oil wells, producing below the bubble point, changes in radial flow geometry and non-Darcy pressure losses due to high flow velocities in gas wells, high rate or high GOR oil wells. Damaged wells with positive skins have straight line IPRs with PIs less than the ideal PI. Straight line IPRs with PIs greater than the ideal are typical of wells with negative skin such as when they have been stimulated, have natural fractures or are highly deviated. The PI is very useful for describing the potential of various wells as it combines all rock and fluid properties as well as geometrical issues in a single constant making it unnecessary to consider these properties individually.

Figure 2.M- Effect of Damage And Fractures on a Well’s PI

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Oil Well - Vogel’s Two Phase Flow IPR The previous straight line IPR does not hold with two phase flow (gas and liquid) in the reservoir. Once the BHFP falls below the bubble point pressure, gas saturation builds up around the wellbore which reduces the permeability to liquid which of course reduces well productivity at that particular drawdown compared to predicted by linear PI. This means the true IPR is curved and, hence the PI J, decreases with increasing drawdown (slopes 1 and 2 in figure 2.o). There may also be some non-Darcy gas flow effects in wells producing below the bubble point. Vogel used a computer programme to model a variety of solution gas reservoirs and developed a generalised IPR reference curve to account for the two phase flow effects below the bubble point. He also presented an approximation using the expression: p =1−0.2 wf qmax  pR q

 p −0.8 wf   pR

  

2

Eq. 2.O

where: pR pwf q qmax

= = = =

Reservoir pressure, psi Bottom-hole flowing pressure, psi Liquid production, stb/d Maximum liquid production rate when pwf = 0, stb/d

Qmax is a theoretical value sometimes referred to as Absolute Open Flow (AOF) of the oil well.

Figure 2.N - Typical IPR Curve for Saturated Reservoir

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Vogel’s equation has been validated through observed field data particularly on pumped wells with high drawdowns where pwf approaches zero. The model used to develop Vogel’s reference curve did not include skin effects which would tend to straighten the IPR curve. Procedures to correct for skin are available.

Figure 2.O - Vogel’s IPR Reference Curve

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Where inflow relationship passes through the bubble point, a straight line IPR is drawn above the bubble point and the curved IPR signifies the two phase flow below this point. For this, Vogel’s equation is combined with the PI to develop a general IPR equation. This has been published by Brown. When the BHFP is above the bubble point use the normal straight line equation: q o =J(p R −p wf )

Eq. 2.P

and when it drops below the bubble point use the modified Vogel equation: p Jp  qo =J(p R −p wf )+ b 1−0.2 wf 1 .8   pb 

 p −0.8  wf   pb

  

2

   

Eq. 2.Q

where: pb

=

Bubble point pressure, psi

If water production is involved, it is dependant upon whether it is produced from the same interval or others. As oil is normally produced from a different zone to the water, the following equations are applied: q w =J(p R −p wf )  p q o =q o max 1−0.2 wf   pR 

Eq. 2.R

 p −0.8 wf   pR

  

2

   

Eq. 2.S

If oil and water both flow from the same zone then the Vogel equation is used for the gross flow rate:  p q o +q w =(q o +q o max )1−0.2 wf   pR

 p −0.8 wf   pR

  

2

  

Eq. 2.T

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Figure 2.P - Combined Straight Line IPR and Vogel IPR Oil Wells - Generalised IPR Curves As described earlier, curvature of the IPR curve is not solely due to the reasons highlighted above but also due to rate dependent skin. This is where Darcy’s law which is good for moderate to low flow rates is affected by high velocities. This non-Darcy flow, or turbulence, is sometimes the most dominant factor especially for gravel packs and high rate gas-liquid ratio wells. Fetkovich recognised that many oil wells could be handled in the same way as gas wells using the curved IPR:

(

q o =C p R −p wf 2

)

2 n

where: C n

= =

Linear deliverability coefficient Deliverability exponent (0.5 to 1.0)

Eq. 2.U

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Golan and Whitson showed how this relationship could be expressed in a similar form to Vogel’s reference curve as:  p = 1− wf q max   p R  q

  

2

   

n

Eq. 2.V

This equation is compared with Vogel’s reference curve in figure 2.q, for two values of the exponent, n. It is seen that when n = 1, the Vogel and Fetkovich IPRs are similar. It is recommended that n be assumed to be 1 where no multi-rate data is available. n is considered as the means to account for non-Darcy flow but there is no theoretical technique for finding it as it is a function of the rate used during testing. If multi-rate data is 2 2 available then a log-log plot of q versus (pR - pwf ) will give a straight line with a slope of 1/n.

Figure 2.Q - Vogel And Fetkovich IPR Curve Comparisons Use of this approach will provide better results than Vogel’s method, however it requires four points at widely different flow rates to maximise the benefit of this method. If such data is not available, n should be assumed as 1. Blount and Jones presented an alternative generalised IPR equation which was an extension to the Forcheimer equation to include the non-Darcy flow effects: p R −p wf =aq+bq 2

Eq. 2.W

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The Darcy flow coefficient, a, can be determined theoretically for a well producing at pseudo-steady state flow in the middle of a circular reservoir: a=

141.2µ o B o   re ln kh   rw

  −0.75+S  

Eq. 2.X

The skin term, S, is relative to all non-rate dependent skin contributions. The other non-Darcy flow coefficient, b, can also be found theoretically but requires a knowledge of the turbulence factor, β, which is rarely measured in the laboratory. Similarly, it takes no account of completion non-Darcy effects such as inefficient perforating, etc. Again, if multi-rate test data is available, both a and b can be determined using a plot of (q R - pwf)/q versus q gives a straight line with a slope of b and an interception of a. In very high permeability wells, coefficient b can be much greater than b and perforating efficiency (shots/ft and penetration) is a very important to productivity. Oil Wells - Predicting Future IPRs Estimates of future IPR curves throughout the life of the reservoir are frequently required for production forecasting and planning artificial lift designs. The effects of increasing water influx on the gross PI, described earlier in Section 2.2, leads to a significant increase in skin due to scaling, mobilisation of fines, skin damage during remedial operations and reduced contribution from reduced pay through plugging back. In solution drive reservoirs, the reservoir pressure will decline against time, shifting the IPR curve downwards resulting in a decline of the production rate and causing flow instability. The relative permeability to oil will also decrease due to increased gas saturation further shifting the curve downwards. The liberation of gas also affects the oil fluid properties. Standing presented a method of predicting future IPR curves by the equation:

J * future J * present

 k ro     µ o B o  future =  k ro     µ o B o  present

Eq. 2.Y

and: q future =J * future

  p p R future 1−0.2 wf  p R future   

  −0.8 p wf   p Rfuture  

2      

Eq. 2.Z

where: J*

=

PI at minimal drawdown (i.e. where two phase flow effects are negligible)

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J* at present conditions is established by carrying out a well test or theoretically. Relative permeabilities and fluid saturations are determined from special core analysis data and reservoir material balance analysis (using either analytical calculations or a reservoir simulation model). Fluid viscosities and volume are determined from PVT correlations. If data for Standing’s equation are not available, the simpler approach like Fetkovich relation for predicting qmax in Vogel’s reference curve. Eickmeier first proposed an expression based on Fetkovich’s work, which in modified form is: q max .present  p Rpresent = q max .future  p R future

   

m

Eq. 2.AA

It may be shown theoretically that exponent m could vary between 1 and 3. An exponent of 2.5 gives the best fit to the gas drive IPR curves by Vogel while values of 1.66 have been found in actual field studies by Eickmeir. Gas Wells - Simplified Deliverability Relationship Rawlins and Schellardt developed a simplified gas well back-pressure equation which relates gas flow rate to the BHFP and is the well Known AOF equation;

(

p g =C p R −p wf 2

)

2 n

Eq. 2.BB

This equation was developed empirically using several hundred multi-rate gas well test data and not by theory but satisfactorily describes the behaviour of the gas well tests considered. The exponent, n , in the equation must be estimated from one of a number of well test methods (e.g. isochronal test) due to there being no accepted theoretical basis available. A 2 2 log-log plot of (pR - pwf ) versus q is conducted from which the slope gives the value of 1/n. This exponent can vary between 1.0 for laminar flow to 0.5 for fully turbulent flow. Obviously at low to moderate rates there is little turbulence and n is close to 1, however in high rates this is highly improbable and makes the IPR projections almost impossible and erring on the optimistic side. It is, therefore, critical that well tests are conducted up to or above the rate of intended production. The constant C is also found from the log-log plot and varies as a function of flow time until it reaches a constant pseudo-steady state. In some instances C can be calculated from reservoir parameters, using kh and S from build-up data but is only applicable if flow is laminar (n = 1). To obtain a value of n, it is normal to test the well at three rates at a fixed period of time followed by a single rate until stabilisation is reached to obtain C. The problem with this isochronal test is the time required to reach stabilised flow in tight gas sands which could be months. While this method is widely used throughout the industry, it is not recommended for estimating IPRs as it lacks the theoretical basis and other rigorous equations are available.

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Gas Wells - Generalised Deliverability Due to the shortcomings of the back-pressure equation described above and since turbulence which is common in gas wells, it must be accounted for properly and a theoretical based method is more often used in modern engineering. The expression below is based on the work of Forchemier and is: p R −p wf = Aqg + Aqg

Eq. 2.CC

2

The Darcy and non-Darcy coefficients, A and B, are determined in a similar manner as the 2 2 generalised IPR equation for an oil well, however the straight line plot is (pR - pwf )/q versus q. It will be seen that the gas IPR is curved even when the non-Darcy term is 0. eq. 2.cc is not precisely correct since inherent in its derivation is an assumption that the product of µ and z is constant. For most gas compositions this is valid only at pressures less than approx 2,000psi or if drawdown pressure changes are small which is the case in high permeability wells above 3,000psi when µz is proportional to pressure, an equation similar to eq. 2.w can be used. Between 2,000psi and 3,000psi, there is curvature in the plot of µz against p making neither approach applicable. In this range the correct inflow equation is written in terms of pseudo-pressures:

m(p)=2

Eq. 2.DD

p dp pb µ z g

∫

p

where: µg z

= =

Gas viscosity, cp Gas deviation factor

and where the integration limits are substituted with the pressure range being considered, normally pg and pwf for inflow calculations, hence: m(p R )−m(p wf )= Aq g +Bqg

Eq. 2.EE

2

where: A

=

1422

T   re ln k g h   r w

B

=

1422

TD k gh

  −0.75+S  

Here the results of the multi-rate test would be plotted as m(pg) - m(pwf)/q versus q to find a value of B from the slope and to check the value of A from the intercept. The non-Darcy coefficient B can also be calculated theoretically but, as for oil wells, requires knowledge of the correct turbulence factor, β. The non-Darcy skin is also frequently accounted for by using: m(p R )−m(p wf )=1422

q g T   re ln k gh   rw

  −0.75+S+Dqg   

Eq. 2.FF

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where: D qg T S D kg

is = = = = =

Derived from well tests Gas flow rate, mscf/d o Reservoir temperature, F The sum of all non-rate dependent skin Rate dependent skin Effective gas permeability, md

As modern test analysis use computer software, the pseudo-pressure values are readily available, therefore there is a growing trend to use gas pseudo pressures for predicting gas well IPRs at all pressure conditions although the pressure squared method has a use in the field for convenience. 2.4.2.

Reservoir Simulation For IPR Curves Reservoir simulation is commonly used in the development, planning and reservoir management of many fields today. With the use of simulation the production engineer is able not only to predict pressures, WORs and GORs to obtain production targets, but also to generate IPR curves for determination of how current and future well IPRs will vary across the field. To obtain the best use of simulation studies, a model needs to be set up by the reservoir engineer with input from the production engineer. Typically the following should be addressed: • •

• •

• •

Assumptions on the minimum permissible value of Pwf as dictated by the outflow performance altered by varying water-cut, artificial lift or use of compression. Variations between the ideal IPRs and actual IPRs which may be expected from the undrilled well locations. This information is derived from well test results and is input into the models theoretical IPR equations as skin factor. Future stimulation or any damaging effects need to be considered. Long term effects from well interventions, workovers and movement of fines will have on near wellbore performance causing changes of skin during the life of the project. Using expected off takes, predict turbulence and two phase flow effects by the use of total skin S’ inclusive of near wellbore and rate dependent skin effects. The value of D (Refer to eq. 2.ff) can also be directly entered into some simulators. If a PI is entered in rather than skin, well radius, etc., it will be necessary to correct it for the grid block’s size and shape. Outflow performance curves should be derived from an accurate computer programme as some programmes are not rigorous in the handling of two phase flow.

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The results from such field models will provide the reservoir pressure, production rates and wellbore saturations at various time steps, however judgement is required when using these results, in particular check: • • • • •

Confirm if non-Darcy and multi-phase flow effects have been taken into consideration. Input on skin is realistic for the period covered. Ensure that proposed completion effects on near wellbore performance, e.g. gravel packing, partial completion, deviation, stimulation, etc. have been considered. If the reservoir pressure refers to grid block or to the drainage area. Whether rates have been modified for downtime due to maintenance, workover or sales contracts, etc.

As the use of full field reservoir simulation requires many assumptions and simplifications are made to manage the problem, therefore the predicted flow rates should not be considered as precise and the relevant reservoir engineer should be consulted to establish the accuracy. They may also be able to advise on possible sudden changes in water cut or gas production due to conning or cusping. Often more reliable predictions in shape of the well IPR can be achieved by engineers using single well models to study the probability of water or gas conning or to model transient well test results. It is also used to determine the sensitivity of production to drawdown and optimise perforating strategy. When and as new well data from log and RFT/DST results becomes available, it should be used to update the generalised IPR to reflect the actual pay interval, reservoir quality, skins, saturations, pressure and mechanical data. From this, revisions can be made to the completion designs, programmes and production forecast. After using measured IPR curves, the model needs to be updated to include actual log and test results. Once this achieved, then the model can be used to evaluate the effect of depletion, water breakthrough and saturation changes on production and used for artificial lift studies. Care must be exercised, however, in extrapolating the shape of the IPR and determining the effects by well operations and production may have on skin. It is extremely important that production engineers understand that the uncertainties involved and do not give greater reliability on model studies than reasonably can be expected.

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IPR Selection In developing representative IPRs for a field, the appropriate IPR model needs to be selected based upon the anticipated production conditions. These are summarised again in the following table: Type Of Well

Producing Conditions

Recommended IPR Model

Undersaturated oil

Pwf > pb

Linear PI or radial flow equation

Saturated oil

Pwf < pb

Vogel or Fetkovich

Damaged saturated oil

Pwf < pb S > +3

Standing or linear PI if very damaged (S > 7)

PR > pb

Composite Vogel and linear

Undersaturated oil at pR but saturated at pwf

Pwf < pb

Wells producing oil and water

WC > 0

Use as above for the appropriate oil and linear PI or radial flow equation for water

WC > 90%

Linear PI or radial flow equation

High rate undersaturated oil

q > 25stb/d/ft

Blount - Jones or radial flow equation with turbulence

High rate saturated oil

q > 25stb/d/ft

Blount - Jones

Water zone

Pwf < pb Gas wells

Pseudo-pressure equation 2

(m(pR) - m(pwf) = Aq + Bq ) Omit B if only single rate data available Table 2.A - IPR Selection Based on Reservoir Type The appropriate technique will also depend on the reservoir data that is available which is function of the development stage. The selection of an IPR model based on this is given in table 2.b.

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Radial Flow Equation

0

Reservoir Model IPRs

Empirical IPRs

Technical Evaluations Prospect evaluation

Guestimate potential.

-

-

Exploration well results

Extrapolate test results.

-

Validate interpretation

Conceptual design, large field

Primary method.

Identify variations geographically with time.

Validate results. Highlight damage risks.

Conceptual design, small field/single well

Primary method.

-


Development plan

Validate results and skin assumptions.

Primary method.


Detailed design, large field

Validate results. Evaluate completion results.

Primary method.


Detailed design, small field/single well

Primary method. Evaluate completion methods.

If available, use for future IPRs.


Development Planning

Optimising Operations/ Workover Well performance assessment

Estimate skin and determine cause.

-

Primary method.

Field studies (forecasts/ artificial lift, lift/ compression)

Primary method for post workover IPR

Predict future IPR

Primary method for current IPRs.

Workover planning

Primary method for post workover IPR.

Predict future IPR

Primary method for current IPRs.

Revised development plan

Define model input

Primary method.

Validate reservoir model results.

Table 2.B - IPR Selection Based on Development Stage

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Outflow Performance Tubing Performance Predicting fluid flow behaviour in tubing involves combining the basic fundamentals of mass momentum and energy conservation with complex mass transfer phenomena for multicomponent hydrocarbon mixtures. Application of these concepts, results in utilising the following interrelated topics: • • •

Phase behaviour. Flowing Temperature prediction. Pressure drop prediction.

The relationship between pressure and temperature drop in wells and PVT behaviour is complex. Pressure drop is determined using empirical and semi-empirical correlations and carried out on computer software programmes. Refer to the following sections. The methods for predicting pressure and temperature drops are addressed in the following sections. PVT Relationships There are two PVT methods used in the prediction of mass transfer between oil and gas, the ‘black oil’ model and the ‘compositional’ model. The black oil model assumes a constant composition for the liquid phase and accounts for mass transfer using the parameters gas-oil ratio and formation volume factor. The variable composition model requires performing vapour-liquid equilibrium (VLE) or ‘flash’ calculations to determine the amount and composition of both the gas and liquid phases. Each model uses differing methods to determine the densities and viscosities for each phase and interfacial surface tension. In general the black oil model is easier to use than the compositional model. Oil Well - PVT Relationships With most modern software programmes there are four methods of obtaining PVT properties for oil wells which are listed in order of preference. In the vast majority of cases there are sufficient data to use the tuned black oil model correlation method. • • • •

Interpolate directly from experimental data. Interpolate from compositional simulation data. Tuned black oil model empirical correlations. Untuned black oil model empirical correlations.

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The approach adopted when choosing the appropriate method for each application should be: a)

Use the black oil model flash vaporisation lab data if they are available. Do not use differential separation data since it is not representative of the vaporisation that occurs in the tubing.

b)

Use the tuned empirical correlations for black oil model variables if the appropriate although limited experimental data are available.

c)

Use black oil model parameters generated from results of compositional simulation if it has been performed for incidental reasons, e.g. reservoir or production reasons, but only if experimental data is not available.

d)

Do not use untuned black oil model empirical correlations unless the data available cannot justify a more rigorous method.

Gas/Gas Condensate Wells - PVT Relationships In software programmes, PVT properties for gas and gas condensate wells must be described with the compositional model. Black oil models parameters should never be used to predict PVT properties for gas or gas condensate systems. Temperature Drop Calculation Predicting the temperature loss in the wellbore as a function of depth and time is necessary to determine PVT properties for use in calculating pressure drop. Some software programmes, temperature profiles may be specified in five ways: • • • • •

Linear profile based on measured or assumed wellhead and bottom-hole temperatures. Profile based on adiabatic heat transfer, i.e. constant temperature throughout the length of the string. Profile based on a specified heat transfer coefficient. Profile based on conservation of energy that utilises complex wellbore heat transfer calculations. Profile based on a simplified version of the complete rigorous calculation involving correlating parameter for which there is unavailable information but with data which are available.

The linear profile is the most widely used due to the complexity of heat transfer calculations in conjunction with the lack of sufficient measured data. Although the linear approach is unrealistic, the error has been found to be less than 15% in overall temperature drop in typical wells. However, in gas wells it has amore significant effect. Some wells have produced fluids with special properties that are very sensitive to temperatures and more complex heat transfer calculations are required. These are: • • •

Gas condensate wells with retrograde condensate. High pour point crude oil wells. Wells in which hydrate formation can occur.

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Pressure Drop Calculation Calculating pressure drop in tubing involve numerical integration of the steady-state pressure gradient equation over the entire tubing length. The equation consists of three components and can be expressed as follows: dp  dp   dp   dp  =  +  +  dL  dL HYD  dL FR  dL  ACC

Eq. 2.GG

pgsin θ  dp   =  gc  dL HYD

Eq. 2.HH

where:

is the pressure gradient caused by the hydrostatic head of potential energy of the multiphase liquid. f pv 2  dp   =   dL FR 2g c D

Eq. 2.II

is the pressure gradient caused by wall friction. p vdv  dp  =   g c dL  dL  ACC

Eq. 2.JJ

is the pressure gradient caused by fluid acceleration. In multi-phase systems, the variables such as p and v in the pressure gradient equation are normally averages for the gas and liquid phases present, therefore, the pressure is sensitive to the relative amounts of gas and liquid present at any location in the tubing. The hydrostatic head is the most predominant component of the pressure gradient in oil wells, often accounting for 90% of the pressure drop. The friction losses are the remainder of the pressure loss and are more significant in gas wells with acceleration effects being negligible except when near to atmospheric pressure. Gas and oil phases normally flow at different speeds which is the phenomenon referred to as slippage. This slippage causes an additional accumulation of liquid in the tubing which is termed liquid hold up. The amount of slippage that occurs is dependent upon the geometrical distribution of the gas and liquid in the pipe, referred to as the ‘flow pattern’ or ‘flow regime’. Flow patterns are governed primarily by the flow rates of each phase, tubing diameter and to a lesser extent PVT properties.

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Typical flow patterns are: • • • • •

Annular flow Churn flow Slug flow Bubble flow Liquid flow.

Considering the above, it is obvious that the pressure at each point in the well and, therefore, the total pressure drop is very dependent on flow pattern. Typical pressure gradients in wells for different flow patterns are: • • • •

Single phase oil Bubble flow Slug flow Mist flow

= = = =

0.36psi/ft 0.25psi/ft 0.20psi/ft 0.1 - 0.2psi/ft

Hence, it is seen that prediction of pressure drop in multi-phase systems is complex and has led to the development of different correlations to be used. Although many of these have been successful to some degree, no single method has been universally been accepted. The early developed correlations assumed the flow as homogeneous mixtures ignoring liquid hold up effects. Attempts were made to compensate for these errors in the equations by single empirical derived friction factor. Subsequent correlations were developed to predict liquid hold up but most of these first required an empirical correlation or ‘map’ to predict the flow pattern. The accuracy of existing correlations for predicting flow pattern, liquid hold up pressure gradient is limited by the ranges of data used in their development and no single method can be applied universally. More recent models developed based on flow mechanisms and conservation principles, referred to as mechanical models, offer more potential for accurate predictions but these are not readily accepted as standard design methods as yet. Some software programmes use all the correlations available and the more recent promising mechanical models can be added. Flow Patterns Transition between the various flow patterns, as listed in the previous section, can be identified using flow pattern maps. The most common maps are empirically derived with coordinates based on dimensionless groups of variables that include volumetric flow rates, diameter and PVT properties. Although bubble, slug and churn floe predominate in oil wells, it is possible for oil and gas wells to include all flow patterns in addition to single phase liquid and gas.

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Classification Of Methods Published methods of multi-phase flow pressure gradients in wells can be placed into one of three general categories based on the assumptions from which the method was developed: • • • •

Homogeneous flow correlations where slippage and flow pattern are not considered. Slip flow correlations where slippage is considered but not flow pattern. Flow pattern dependent correlations where liquid hold up and flow pattern are considered. Mechanised models where slippage, flow pattern and basic flow mechanisms are considered.

Oil Well Correlations Oil well correlations for predicting pressure gradients in oil wells have been published and those most widely accepted in the Industry are: • • • • •

Duns and Ros (1963) Hagedorn and Brown (1967) Orkiszewski (1967) Aziz, Covier and Fogarasi (1972) Beggs and Brill (1973).

As illustrated in figure 2.r and figure 2.s, these correlations predict different pressure drops for the same application, however any one of these may be successful in a given field. Validation and actual field data are the only means of choosing a pressure loss method but this is not available at the time of designing the completions. Ansari recently performed an evaluation of the most widely used correlations and his own proposed mechanistic model., performed using the TUFFP well databank consisting of 1775 flowing well surveys covering a broad range of production variables and pressure loss methods were also evaluated for each flow pattern. table 2.c presents the overall results below:

Average Error

Absolute Average Error

Standard Deviation

Relative Performance Factor, RPC

Ansari

9.3

101.3

163.9

1.000

Hagbr

-28.5

102.8

178.4

1.132

Dunros

33.4

110.9

177.7

1.178

Aziz

-20.8

116.6

190.4

1.198

Begbril

41.3

134.9

207.9

1.404

Orkis

12.2

151.3

273.3

1.597

Mukbr

78.7

159.8

217.2

1.666

Method

Table 2.C - Evaluation of Pressure Loss Methods Using TUFFP Well Databank

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Selecting the best prediction method from table 2.c is not appropriate as the best statistical results do not guarantee the best performance for a specific application. The choice must be made on experience. The applicability of the various methods is compared in table 2.d.

Figure 2.R - Comparison Lift Curves for High Gas-Oil Ratio Well

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Figure 2.S - Comparison of Lift Curves for Low Gas-Oil Ratio Well

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Method

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Category

Accuracy

Data

Fluids

Application/Comments

Mechanistic Model

Good

N/A

N/A

Appears a little conservative. Gives consistent results for all flow patterns and TCP minimum. Needs to be verified through use.

Flow Pattern Dependent

Variable depending on version

Laboratory and field

Oil, water, gas

Optimistic. tends to under-predict pressure drop.

Brill

Flow Pattern

Poor

Laboratory

Air, water

Developed for deviated wells but tends to significantly over-predict pressure drop. Should be avoided unless well is highly deviated.

Beggs and Brill with Palmer


Fair

Laboratory

Air, water

Developed for deviated wells but tends to over-predict.

Homogeneous

Good in some flow patterns

Field (annular flow)

Oil, Gas

Does not predict a TPC minimum. Usually not applicable for completion design.

Ros


Good

Laboratory , experiment al plus field data

Oil, gas, water

Conservative. Tends to over-predict pressure drop. Good where several flow patterns exist.

and

Slip Flow

Good in some flow patterns

Field experiment

Oil, water, air

Does not predict a TCP minimum. Poor in bubble flow. Liquid hold up prediction can be less than for no slip flow. Should be used with caution.

Hagedorn and Brown with Griffith Bubble and restriction on hold up


Good

Field experiment

Oil, water, air

Optimistic. Tends to under-predict pressure drop. This is the preferred correlation in the absence of other data.

Kleyweg et al Occidental mod (1983)

Slip Flow

Field

Oil, water, Gas

Developed to optimise gas lift in o highly deviated wells (>70 ) in Claymore field. Should not be used except for similar conditions.

Orkiszewski (1967)


Some Hagedorn and Brown data, field

Oil, water, gas

Conservative. Tends to over-predict pressure drop. can cause convergence problems in computing algorithm.

Ansari 1963)

(TUFFP

Aziz et al (!972)

Beggs (1973)

and

Cornish (1976)

Duns (1963)

and

Hagedorn Brown (1965)

Fair

Table 2.D- Applicability of Pressure Loss Prediction Methods Gas And Gas Condensate Correlations For gas and gas condensate wells the following methods are frequently used: • • • •

Cullender and Smith Single phase gas with modified gravities Multi-phase flow correlations Gray correlation.

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As with oil wells, validation with field data is the only reliable method for determining the most appropriate correlation and, similarly, this is never usually available at the time that the completions are designed. If this is the case, the Gray correlation is generally recommended although the Ansari model mat prove to be even more accurate since it includes a good model for predicting pressure gradient in annular flow which is the most predominant in gas wells. Care is needed in the selection of tubing in that, even in low liquid rates, wells can quickly ‘load up’ over a few weeks if it is not correctly sized. Although any of the correlations can be used, the Gray correlation is recommended based on the work with ‘Reinicke et al’ but results should be used with caution. In gas wells, liquid loading can also be predicted using simplified methods presented with Turner et al which are independent of pressure drop calculations. These methods have been reviewed by Lea and Tighe. For wells producing high gas-water or gas-condensate ratios, it is recommended that tubing size be assessed using these methods in addition to lift curve methods and that the most conservative approach be adopted. Effect Of Deviation Angle Nowadays most wells of interest to operators are directional or deviated wells. The accuracy of pressure drop calculations in these circumstances using correlations developed for vertical is obviously extremely questionable. Flow pattern and liquid hold up is very dependent on deviation angle. For wells with o deviations up to 45 from vertical, vertical correlations perform accurately enough for wells o greater than 45 , accounting for deviation by simply using the sine in the hydrostatic component of the pressure gradient equation may not be adequate in these cases, either the Beggs and Brill correlation or a mechanistic model would be necessary. In any study, differing correlations should not be used for different deviations, as the difference between the predicted pressure drops is generally greater than the effect of the deviation itself. Effect Of Restrictions Most oil and gas wells contain some types of flow control devices in the completion which choke flow. The geometry of these restrictions varies from a simple reduced diameter axial flow path to a tortuous complex path. When a multiphase mixture flows through a restriction, the phase velocities dramatically increase. If these reach sonic velocity, critical flow occurs. For critical flow, simple empirical correlations such as the Gilbert equation are sufficiently accurate. For sub-critical flow, behaviour is very dependent on geometry and a simple Bernoulli type equation with a discharge coefficient is recommended.

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Effect Of Erosion Erosion in completions occurs when there are high velocities and if there are solids particles in the flow stream. The most common points for erosion is where there are restrictions which cause increased velocities. The API have published a method in API RP 14E, to determine the threshold velocities for erosion to occur in piping systems but the validity of this for all conditions is questionable. 2.4.5.

Flow Rate Prediction Following the establishment of both the IPR and TPC, they must be presented in the same plot from which the intersection of the lines can be used to predict the flow rate of a well at given set of stable flow conditions (Refer to figure 2.t ). Changing the system parameters like the tubing ID, reservoir pressure, GLR, etc., will effect either or both the IPR and TPC and in consequence alters the production rate. Systematically varying the system parameters allows comparison of the incremental effects on production and these can, in turn, be forecast and analysed for cost/benefit of the completion options. Continuing in this manner provides information on which decisions can be made on optimum well configuration or optimum operating conditions. This section describes this analysis.

Figure 2.T - Combining IPR and TPC Curves

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Natural Flow Point The characteristic ‘J’ shape of the TPC means there can be several possible intersections with the IPR as shown in figure 2.t through figure 2.v. The TCP, Pmin, occurs due to the gas and liquid phase velocities differ at low flow rates, i.e. slippage occurs. At low flow rates, the hydrostatic component in the total pressure drop predominates. As liquid velocities tend toward zero, the gas escapes from the well and the hydrostatic gradient approaches the static pressure of the liquid. On the other hand, as the flow rate increases, the hydrostatic component reduces due the gas lift effect while the friction component increases until the minimum is reached when the friction pressure drop exactly offsets the decrease in hydrostatic pressure drop. In figure 2.t, the IPR and TPC curves intersect well to the right of the minimum and, under these conditions, the well will flow at a stable rate defined as the natural flow point. The optimum tubing size, or GLR, will give an intersection well to the right of the pmin and out of the flat portion of the TCP curve. but without incurring excessive friction losses. If the intersection is either close to or to the left of the minimum (Refer to Figure), the well will tend to head and flow at unstable conditions due to the cyclic build up of liquid and periodic slug lifting by accumulated pressure of the trapped gas. Because of the inaccuracies of the two phase flow correlations and the difficulty in obtaining reliable data in this region, the start of unstable flow conditions is rarely known especially with large size tubing. As the usual aim is to keep to the right of Pmin, this is generally not a problem.

Figure 2.U- Combined IPR and TPC Curves Under Unstable Conditions

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If the natural flow point is in the unstable region, a smaller size tubing or artificial lift system should be considered. Using smaller tubing may result in higher frictional pressure drops and if this reduces flow rates to below uneconomic levels, a tapered tubing string may be a consideration. Where the IPR and TCP curves intersect close to, or to the left of the minimum, the flow will become increasingly unstable and wells with large size tubing will die quickly, whereas small tubing may sustain unsteady flow until the IPR and TPC curves become almost tangential. Where the curves intersect at two rates (Refer to figure 2.v), the intersection point to the left is always unstable and the well will either die or progressively produce more fluid until it reaches the stable flow point. To obtain flow at these conditions, it is necessary to kick the well off quickly.

Figure 2.V - IPR and TPC Curves with Two Apparent Intersection Points

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Artificial Lift Effects A well will not flow naturally if the IPR and TPC curves do not intersect and in this case artificial lift could be used to provide the pressure differential between the curves (Refer to figure 2.w). An artificial lift system places an injection of energy into the flow system which displaces the TPC curve downwards. In a pumping well, the displacement is dependent on the pump performance curve (i.e. pump differential versus rate) which is plotted below the well performance curves as shown in figure 2.w. This results in a combined outflow performance curve termed the pump intake curve. It is necessary when carrying out this analysis, to consider the effect of downhole gas separation on pump outflow performance. In gas lifted wells, the TPC is displaced as a result of the effect of the gas on the density, velocity and flow regime in the tubing above the operating gas lift valve. By generating an outflow performance curve for each potential system, they can be used to compare the deliverability of the various methods. From this an economic cost analysis can be produced to analyse capital and operating cost differences.

Figure 2.W- Combining Pump Performance and TCP Curves

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As shown in the example (figure 2.x below), it is apparent that gas lift will maximise the deliverability of good wells (PI = 2.5std/d/psi) provided 2 7/8ins tubing is installed, while submersible pumping gives the maximum rate from the poorer zones (PI = 0.4 to 1.0stb/d/psi) provided there is no drawdown limitation. Artificial lift is often widely used to improve flow stability and increase the production of existing producing wells, however the operating and capital costs of equipment must be justified against the incremental increase in production rate.

Figure 2.X - Artificial Lift Options for Deep Wells with 5 1/2ins Casing

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3.

WELL TESTING

3.1.

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The main objective when drilling an exploration well is to test and evaluate the target formation. The normal method of investigating the reservoir is to conduct a well test. There are two types of well test methods available: •

Drill Stem Test (DST) Where Drillpipe/Tubing in combination with downhole tools is used as a short term test to evaluate the reservoir.

•

Production Test Many options of string design are available depending on the requirements of the test and the nature of the well.

Many designs of well testing strings are possible depending on the requirements of the test and the nature of the well and the type of flow test to be conducted but basically it consists of installing a packer tailpipe, packer and downhole test tools and a tubing or drill pipe string then introducing a low density fluid into the string in order to enable the well to flow through surface testing equipment which controls the flow rate, separates the fluids and measures the flow rates and pressures. 3.1.1.

Types of Tests Drawdown A drawdown test entails flowing the well and analysing the pressure response as the reservoir pressure is reduced below its original pressure. This is termed drawdown. It is not usual to conduct solely a drawdown test on an exploration well as it is impossible to maintain a constant production rate throughout the test period as the well must first cleanup. During a test where reservoir fluids do not flow to surface, analysis is still possible. This was the original definition of a drill stem test or DST. However, it is not normal nowadays to plan a test on this basis. Multi-Rate Drawdown A multi-rate drawdown test may be run when flow rates are unstable or there are mechanical difficulties with the surface equipment. This is usually more applicable to gas wells but can be analysed using the Odeh-Jones plot for liquids or the Thomas-Essi plot for gas. It is normal to conduct a build-up test after a drawdown test. The drawdown data should also be analysed using type curves, in conjunction with the build up test.

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Build-Up A build-up test requires the reservoir to be flowed to cause a drawdown then the well is closed in to allow the pressure to increase back to, or near to, the original pressure which is termed the pressure build-up or PBU. This is the normal type of test conducted on an oil well and can be analysed using the classic Horner Plot or superposition. From these the permeability-height product, kh, and the near wellbore skin can be analysed. On low production rate gas wells, where there is a flow rate dependant skin, a simple form of test to evaluate the rate dependant skin coefficient, D, is to conduct a second flow and PBU at a different rate to the first flow and PBU. This is the simplest form of deliverability test described below. Deliverability A deliverability test is conducted to determine the well’s Inflow Performance Relation, IPR, and in the case of gas wells the Absolute Open Flow Potential, AOFP, and the rate dependant skin coefficient, D. The AOFP is the theoretical fluid rate at which the well would produce if the reservoir sand face was reduced to atmospheric pressure. This calculated rate is only of importance in certain countries where government bodies set the maximum rate at which the well may be produced as a proportion of this flow rate. There are three types of deliverability test: • • •

Flow on Flow Test Isochronal Test The Modified Isochronal Test.

Flow-on-Flow Conducting a flow-on-flow test entails flowing the well until the flowing pressure stabilises and then repeating this at several different rates. Usually the rate is increased at each step ensuring that stabilised flow is achievable. The durations of each flow period are equal. This type of test is applicable to high rate gas well testing and is followed by a single pressure build up period. Isochronal An isochronal test consist of a similar series of flow rates as the flow-on-flow test, each rate of equal duration and separated by a pressure build-up long enough to reach the stabilised reservoir pressure. The final flow period is extended to achieve a stabilised flowing pressure for defining the IPR. Modified Isochronal The modified isochronal test is used on tight reservoirs where it takes a long time for the shut-in pressure to stabilise. The flow and shut-in periods are of the same length, except the final flow period which is extended similar to the isochronal test. The flow rate again is increased at each step.

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Reservoir Limit A reservoir limit test is an extended drawdown test which is conducted on closed reservoir systems to determine their volume. It is only applicable where there is no regional aquifer support. The well is produced at a constant rate until an observed pressure drop, linear with time, is achieved. Surface readout pressure gauges should be used in this test. It is common practice to follow the extended drawdown with a pressure build-up. The difference between the initial reservoir pressure, and the pressure to which it returns, is the depletion. The reservoir volume may be estimated directly from the depletion, also the volume of produced fluid and the effective isothermal compressibility of the system. The volume produced must be sufficient, based on the maximum reservoir size, to provide a measurable pressure difference on the pressure gauges, these must therefore be of the high accuracy electronic type gauges with negligible drift. Interference An interference test is conducted to investigate the average reservoir properties and connectivity between two or more wells. It may also be conducted on a single well to determine the vertical permeability between separate reservoir zones. A well-to-well interference test is not carried out offshore at the exploration or appraisal stage as it is more applicable to developed fields. Pulse testing, where the flowrate at one of the wells is varied in a series of steps, is sometimes used to overcome the background reservoir pressure behaviour when it is a problem. Injectivity In these tests a fluid, usually seawater offshore is injected to establish the formation’s injection potential and also its fracture pressure, which can be determined by conducting a step rate test. Very high surface injection pressures may be required in order to fracture the formation. The water can be filtered and treated with scale inhibitor, biocide and oxygen scavenger, if required. Once a well is fractured, which may also be caused by the thermal shock of the cold injection water reaching the sandface, a short term injection test will generally not provide a good measure of the long term injectivity performance. After the injectivity test, the pressure fall-off is measured. The analysis of this test is similar to a pressure build-up, but is complicated by the cold water bank.

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DST OBJECTIVE A DST is conducted to determine the productivity characteristics of one specific zone. Currently, analysis can provide good data to help evaluate the productivity of the zone, completion practices, extent of formation damage and if there is a requirement for stimulation. In many cases, actual well production rates can be accurately predicted from DST data as it shows what the well will produce against a gradually increasing back-pressure. From this a Productivity Index (PI) or Inflow Performance Relationship (IPR) can be established (Refer to Section 2.4) and, if the flowing pressure gradient in the tubing can be estimated, then actual producing rates can also be determined. Testing is an expensive and high risk operation and, therefore, should only be conducted for essential data. The starting premise should be that testing is not required unless it is clearly justified. The second premise is that, if testing is warranted, it should be done in the simplest possible manner, avoiding any operations which entail higher risk, such as running wireline or coil tubing through the testing string. By adopting this position, the Petroleum Engineer should not appear to be negative but work towards obtaining essential data, which the company needs rather than that which is nice to have, in the most cost-effective manner. The test objectives must be agreed by those who will use the results and those who will conduct the test before the test programme is prepared. The Petroleum Engineer should discuss with the geologists and reservoir engineers about the information required and make them aware of the costs and risks involved with each method. They should select the easiest means of obtaining data, such as coring, if possible. Such inter-disciplinary discussions should be formalised by holding a meeting (or meetings) at which these objectives are agreed and fixed. The objectives of an exploration well test are to: • • • • • • • •

Conduct the testing in a safe and efficient manner Determine the nature of the formation fluids Measure reservoir pressure and temperature Interpret reservoir permeability-height product (kh) and skin value Obtain representative formation fluid samples for laboratory analysis Define well productivity and/or injectivity investigate formation characteristics Evaluate boundary effects.

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DST STRING The well testing objectives, test location and relevant planning will dictate which is the most suitable test string configuration to be used. Some generic test strings used for testing from various installations are shown overleaf. For more detailed information on well test strings and tooling, refer to the Company ‘Well Test Manual’. In general, well tests are performed inside a 7ins production liner, using full opening test tools with a 2.25ins ID. In larger production casing sizes the same tools will be used with a larger packer. In smaller casing sizes, smaller test tools will be required, but similarly, the tools should be full opening to allow production logging across perforated intervals. For a 5 barefoot test, conventional test tools will usually be used with a packer set inside the 9 /8ins casing. If conditions allow, the bottom of the test string should be 100ft above the top perforation to allow production logging of the interval. In the following description, tools which are required both in production tests and conventional tests are included. The list of tools is not exhaustive, and other tools may be included. However, the test string should be kept as simple as possible to reduce the risk of mechanical failure. The tools should be dressed with elastomers suitable for the operating environment, considering packer fluids, prognosed production fluids, temperature and the stimulation programme, if applicable.

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Figure 3.A- Typical Jack Up Test String With TCP Guns On Permanent Packer

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Figure 3.B - Typical Test String With TCP Guns Stabbed Through Production Packer

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Figure 3.C - Typical Jack Up Test String With Retrievable Packer

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Figure 3.D - Typical Semi-Submersible Test String - Retrievable Packer

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RESERVOIR CHARACTERISTICS Reservoir characteristics that may be estimated from DST analysis include: •

Average Effective Permeability. This may be better than core permeability since much greater volume is averaged. Also effective permeability rather than absolute permeability is obtained. Reservoir Pressure. Measured if shut-in time is adequate, or calculated if not. Wellbore Damage. Damage ratio method permits estimation of what the well should make without damage. Barriers/Permeability Changes/Fluid Contacts. These reservoir anomalies affect the slope of the pressure build-up plot. They usually require substantiating data to differentiate one from the other. Radius Of Investigation. An estimate of how far away, from the wellbore, the DST can ‘see’. Depletion. Can be detected if the reservoir is small and the test is conducted properly.

• • • • •

In summary, the DST if properly applied is an essential tool for the Completions Engineer. 3.4.1.

Pressure Build-Up Analysis Horner Equation Transient pressure analysis is based on the Horner pressure build-up equation which describes the re-pressuring of the wellbore area during the shut-in period as the formation fluids moves into the ‘pressure sink’ created by the flowing portion of the test: p ws =p i −

162.6qµB  t ′−∆t ′  log10   kh  ∆t ′ 

where: pws t’ ∆t’ pi q µ B k h

= = = = = + = = =

Measured pressure in the wellbore during the build-up, psig Flowing time, mins Shut-in time, mins Shut-in reservoir pressure, psig Rate of flow, stb/day Fluid viscosity, cp Formation volume factor, reservoir bbl/stb/day Formation permeability, md Formation thickness, ft

Eq. 3.A

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Conditions which must be assumed during the build-up period for eq. 3.a to be strictly correct are: • • • • •

Radial flow Homogenous formation Steady state conditions Infinite reservoir Single phase flow.

Most of these conditions are met on a typical DST although steady state flow is the condition which may cause most concern particularly at early shut-in time. Horner Build-Up Plot  t ′p + ∆t ′   should yield a Assuming these conditions are met, then a plot of pws versus log10   ′ ∆ t   straight line and the slope (m) of the straight line should be: m=

162.6qµB kh

Eq. 3.B

The constant m is representative of a given fluid having physical properties µB flowing at a rate q through a formation having physical properties kh. figure 3.e shows an idealised Horner Plot with the pressure chart showing very simply how t’p and formation pressure pws at varied shut-in times ∆t’ are picked from the chart and related to the Horner plot. Usually pws is determined at 5min intervals along the shut-in pressure curve. In a multi-phase flow period DST, selecting a value for t’p creates some problem mathematically, however little error is caused by assuming that t’p is the time of the flowing period immediately before the particular shut-in period. With equal flow periods on a multiple flow period DST, this is usually done. With a very short initial flow period, t’p can be assumed to be the total of the flowing times with very little error. In figure 3.e, ,the slope m of the straight line is numerically the difference between the t’p  t ′ + ∆t ′   t ′p +∆t ′   =0 and at log10  p pressure value at log10   ∆t ′ =1.0  ′ ∆ t     If the points are plotted on semi-log paper, m is the change in pressure over one log cycle. The ideal plot is where all the points align up in a straight line but is seldom found in actuality, since ‘after-flow’ or wellbore storage effects cause deviation from the straight line in the early region. As a rule of thumb, four points are the fewest to determine a straight line. An important issue is the time required to approach steady state or straight line conditions, depends on reservoir and fluid characteristics, and flow conditions. Experience has formulated some certain rules of thumb to help determine the shut-in time. One of these is that generally the shut-in pressure must reach at least 65% of the static pressure.

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Prior to type curve matching methods, no analysis of the plot was possible unless the straight line was achieved, however, sometimes reasonable estimates of formation parameters could be made.

Figure 3.E - Idealised Horner Build-Up Plot Reservoir Parameters Obtained By Build-Up Analysis Average permeability, k, can be calculated:: k=

162.6qµB mh

Eq. 3.C

Parameters, viscosity, µ, and formation volume, B, can be estimated from available correlations if the gravity of the crude oil and the gas-oil ratio are determined by measurement. Formation thickness, h, must be the net thickness of the productive zone, determined from electric log analysis. If the net thickness is not available then kh or formation capacity is determined: kh=

162.6qµB m

Eq. 3.D

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If all the parameters are unknown, transmissibility

0 kh is determined: µB

kh 162.6q = m µB

Eq. 3.E

Static reservoir pressure, pi, is obtained by extrapolating the Horner straight line to an ‘infinite’ shut-in time: At infinite shut-in time,

 t ′p + ∆t ′  t ′ + ∆t ′  = 0. = 1.0.0 , or as shown in figure 3.e, log10   ′ ∆t ′ t ∆   st

nd

In figure 3.e, both the 1 build-up and 2 build-up plots extrapolate to the same static pressure lending confidence to the analysis. If the second build-up pressure was lower than st the 1 , them depletion may have occurred. Wellbore damage, is presented by the empirical equation for the dimensionless value, s, skin factor: k t ′p  p −p  +2.85  s=1.151 i ff −log φµcrw  m 

Eq. 3.F

However, this factor cannot be readily applied to specific formations to obtain to show the potential of the zone would be if there was no damage. This was carried on a stage further introducing the concept of damage ratio, DR, which compares the flow rate observed, q, to the theoretical flow rate without damage: DR=

qt qa

An another equation, for calculation of DR based on the skin factor relation of Hurst and van Everdingen, is: DR=

p i −p ff k t ′p

  −2.85  m log 2  φµcr w 

where: pi pff c Φ µ rw k t’p

= = = = = = = =

Shut-in reservoir pressure, psi Formation pressure at flow time T, psi (final flowing pressure) Fluid compressibility, vol/vol/psi Formation porosity, fraction Viscosity of reservoir pressure, cp Well bore radius, ins Effective permeability, md Flowing time, mins

Eq. 3.G

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Reservoir And Fluid Anomaly Indications Many times the Horner build-up equation does not hold up under actual case. If changes occur within the radius of investigation of the DST, they can be detected by a change in shape of the slope of the of the line. If it is seen that the rate of flow q remains constant, then permeability k or fluid viscosity µ are likely suspects for change as the wave of increasing pressure travels towards the wellbore. Permeability may change due to natural lensing or formation damage but it is doubtful that formation damage would affect sufficient volume of formation to be detected as a change of slope on the build-up plot. Fluid viscosities change by phase change or type of fluid. ‘Seeing’ a gas-liquid contact from an up-structure well would be difficult due to the normally short radius of investigation through a gas column. Alternatively, seeing a gas-liquid contact from a down-structure well is a much more likely possibility. A sealing barrier such as a fault or permeability pinchout can cause a change of slope m. If the barrier is a straight line as A - A’ in figure 3.f , then the build-up slope will change by a factor of 2. In summary, a change in permeability, viscosity, or existence of a barrier, can cause a change in the slope of the Horner plot, therefore the fact that a change of slope appears on the build-up plot, leaves open the question of what caused the anomaly. This must be resolved through other geologic or reservoir information.

Figure 3.F - Effect of a Fault

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The distance to the anomaly, ra, whether it be a barrier, change of permeability, or a fluid contact, can be calculated:  − 3,793r 2 a φµc   t + ∆t a =2.303ln p − E  ∆t   kt p a   

   

Eq. 3.H

where: ra Tp ∆ta -E

= = = =

Distance to anomaly, ft Flow time, hrs Shut-in time at the point of slope change, hrs Exponential integral value.

Radius Of Investigation The following equation from Van Poollen may be used to estimate the radius of investigation of any particular DST in an infinite radial flow system: ri =

Eq. 3.I

kt i 5.76×10 φµc 4

where: ri tp

= =

Radius of investigation Flow time, mins

Needless to point out, the longer the flowing time, the deeper the radius of investigation. Depletion As explained previously, if the extrapolated pressure from a second build-up is lower than the initial pressure of the first build-up, then depletion may be the cause. Obviously, a reservoir would need to be extremely small for this to occur, however there is plenty of field examples to prove that it occurs. Another reason that a recorded initial shut-in pressure may be higher than true shut-in pressure. This effect is termed supercharged which may be caused by leak off of filtrate over-pressuring the formation. This effect needs to be diagnosed to confirm supercharging.

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Reservoir Parameters - Gaseous System When conducting DSTs of gas zones, flow rate is calculated in scf/day or if in large quantities mscf/d. This involves correcting for deviation of the reservoir gas from the o perfect gas law using the gas deviation factor, Z. and the absolute temperature factor, R. For the Horner build-up plot, the square of the formation pressure, pws, during the build-up is  t ′p + ∆t ′   as shown in figure 3.g. plotted versus    ∆t ′  If the SG of the gas is known, the values of Z and µ can be found from standard testing literature.

Figure 3.G - Typical Horner Plot - Gas well Equations for permeability, estimated wellbore AOFP for a gas zone are: Permeability: k=

1637 q g Tf µZ mg h

where: Z Qg Tf mg

= = = =

Gas deviation factor Rate of flow, mscf/day o o Formation temperature, R = ( F + 460) Horner build-up slope for gas well

Eq. 3.J

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Wellbore Damage: 2 2 p −p i ff EDR = 1   m g  log t + 2.65  p  

Eq. 3.K

Absolute Open Flow Potential Using the single point back-pressure test method: AOF=

( )

qg p 2 i

(p

2

n

Eq. 3.L

)

2 n i −p i

where: n is an exponent varying between 0.5 and 1.0

If n=1.0Max AOF=

qg p 2 i

Eq. 3.M

p 2 i −p 2 ff

If n=0.5Max AOF=

qg p i

Eq. 3.N

p 2 i −p 2 ff

Type Curve Methods There are several type curve methods are available for analysing early time DST data from pressure transient tests. Although these methods are generally used on longer term production tests, they can be used on DST analysis to salvage some information from a test where sufficient data not available to obtain a straight line. Ramey, McKinley and Earlougher-Kersch methods have applications with McKinley being the easiest to use but the others perhaps more accurate. It should be iterated that the Horner should be used whenever possible and type curves used to in picking correct straight line by indicating when wellbore storage effects have ended.

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Basics Of DST Operations In simple terms, a DST is carried out by running test tools in a BHA on a test string in the hole (Refer to previous Section 3.3). When the string is successfully installed and all pressure and function testing is completed, a fluid is circulated into the tubing to provide an underbalance to allow the well to flow after perforating. The downhole tester valve is opened to flow the well to clean up perforating debris and invasive fluids from the formation, the tester valve is then closed to allow the formation fluids to build-up back up to reservoir pressure which is recorded on pressure recorders or gauges. 1

After a suitable time (usually 1 /2 times the flow period), the tester valve is then reopened to conduct the planned flow and shut-in periods in accordance to the programme requirements to obtain other additional data and verification. figure 3.h shows a typical schematic of a simple single flow operational sequence.

A description of the tools used in DST test strings are outlined in the next section. Figure 3.H - DST Typical Sequence of Events 3.4.3.

Common Test Tools Description Refer to the Company ‘Well Test Manual’. Bevelled Mule Shoe If the test is being conducted in a liner the mule shoe makes it easier to enter the liner top. The bevelled mule shoe also facilities pulling wireline tools back into the test string. If testing with a permanent packer, the mule shoe allows entry into the packer bore.

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Perforated Joint/Ported Sub The perforated joint or ported sub allows wellbore fluids to enter the test string if the tubing conveyed perforating system is used. This item may also be used if wireline retrievable gauges are run below the packer. Gauge Case (Bundle Carrier) The carrier allows pressure and temperature recorders to be run below or above the packer and sense either annulus or tubing pressures and temperatures. Pipe Tester Valve A pipe tester valve is used in conjunction with a tester valve which can be run in the open position in order to allow the string to self fill as it is installed. The valve usually has a flapper type closure mechanism which opens to allow fluid bypass but closes when applying tubing pressure for testing purposes. The valve is locked open on the first application of annulus pressure which is during the first cycling of the tester valve. Retrievable Test Packer The packer isolates the interval to be tested from the fluid in the annulus. It should be set by turning to the right and includes a hydraulic hold-down mechanism to prevent the tool from being pumped up the hole under the influence of differential pressure from below the packer. Circulating Valve (Bypass Valve) This tool is run in conjunction with retrievable packers to allow fluid bypass while running in and pulling out of hole, hence reducing the risk of excessive pressure surges or swabbing. It can also be used to equalise differential pressures across packers at the end of the test. It is automatically closed when sufficient weight is set down on the packer. This valve should ideally contain a time delay on closing, to prevent pressuring up of the closed sump below the packer during packer setting. This feature is important when running tubing conveyed perforating guns which are actuated by pressure. If the valve does not have a delay on closing, a large incremental pressure, rather than the static bottom-hole pressure, should be chosen for firing the guns Safety Joint Installed above a retrievable packer, it allows the test string above this tool to be recovered in the event the packer becomes stuck in the hole. It operates by manipulating the string (usually a combination of reciprocation and rotation) to unscrew and the upper part of the string retrieved. The DST tools can then be laid out and the upper part of the safety joint run back in the hole with fishing jar to allow more powerful jarring action.

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Hydraulic Jar The jar is run to aid in freeing the packer if it becomes stuck. The jar allows an overpull to be taken on the string which is then suddenly released, delivering an impact to the stuck tools. Downhole Tester Valve The downhole tester valve provides a seal from pressure from above and below. The valve is operated by pressuring up on the annulus. The downhole test valve allows downhole shut in of the well so that after-flow effects are minimised, providing better pressure data. It also has a secondary function as a safety valve. Single Operation Reversing Sub Produced fluids may be reversed out of the test string and the well killed using this tool. It is actuated by applying a pre-set annulus pressure which shears a disc or pins allowing a mandrel to move and expose the circulating ports. Once the tool has been operated it cannot be reset, and therefore must only be used at the end of the test. This reversing sub can also be used in combination with a test valve module if a further safety valve is required. One example of this is a system where the reversing sub is combined with two ball valves to make a single shot sampler/safety valve. Multiple Operation Circulating Valve This tool enables the circulation of fluids closer to the tester valve whenever necessary as it can be opened or closed on demand and is generally used to install an underbalance fluid for brining in the well. This tool is available in either annulus or tubing pressure operated versions. The tubing operated versions require several pressure cycles before the valve is shifted into the circulating position. This enables the tubing to be pressure tested several times while running in hole. Eni-Agip’s preference is the annulus operated version. Drill Collar 3

Drill collars are required to provide a weight to set the packer. Normally two stands of 4 /4 ins drill collars (46.8 lbs/ft) should be sufficient weight on the packer, but should be regarded as the minimum. Slip Joint These allow the tubing string to expand and contract in the longitudinal axis due to changes in temperature and pressure. They are non-rotating to allow torque for setting packers or operating the safety joint.

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Crossovers Crossovers warrant special attention, they are of the utmost importance as they connect every piece of equipment in the test string which have differing threads. If crossovers have to be manufactured, they need to be tested and fully certified. In addition, they must be checked with each mating item of equipment before use. 3.4.4.

Tools Utilised With Permanent Packer Systems A permanent or permanent retrievable packer arrangement is used on a Jack-up or Land Rig test utilising a production Xmas tree. Pressure Operated Bypass Valve This allows the test string to be stabbed into the packer in an un-performed well. The tool equalises pressure between the sump and the annulus when the tester valve is closed, preventing the sump from being pressured up due to the volume of the seal assembly entering the packer. The valve is very similar to the circulating valve (bypass valve) except it is closed by annulus pressure instead of weight. If the tester valve can be run in the open position then this valve is not required. Sub-Surface Safety Valve A subsurface safety valve is often run for safety being placed at least 100 ft below the mud line. A control line is run to the valve through a conventional tubing hanger/spool arrangement. The designs can be like a modified lubricator valve or a completion type subsurface safety valve. Some versions required by other operators are installed in the string immediately below a surface test tree in the BOP stack arrangement but this does not provide safety in the ultimate catastrophic situation when there is a collision by another vessel. Tubing Hanger This will be spaced out to position the packer seal assembly into the packer and land off in the tubing hanger spool.

3.4.5.

Sub-Sea Test Tools Used On Semi-Submersibles The sub-sea test tree (SSTT) assembly includes a fluted hanger, slick joint, and sub-sea test tree. Fluted Hanger The fluted hanger lands off and sits in the wear bushing of the wellhead and is adjustable to allow the SSTT assembly to be correctly positioned in the BOP stack so that when the SSTT is disconnected the shear rams can close above the disconnect point.

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Slick Joint (Polished Joint) The slick joint (usually 5ins OD) is installed above the fluted hanger and has a smooth (slick) outside diameter around which the BOP pipe rams can close and sustain annulus pressure for DST tool operation or, if in an emergency disconnection, contain annulus pressure. The slick joint should be positioned to allow the two bottom sets of pipe rams to be closed on it and also allow the blind rams to close above the disconnect point of the SSTT. Sub-Sea Test Tree The SSTT is a fail-safe sea floor master valve which provides two functions; the shut off of pressure in the test string and; disconnection of the landing string from the test string due to an emergency situation or for bad weather. The SSTT is constructed in two parts; the valve assembly consisting of two fail safe closed valves and; a latch assembly. The latch contains the control ports for the hydraulic actuation of the valves and the latch head. The control umbilical is connected to the top of the latch which can, under most circumstances be reconnected, regaining control without killing the well. The valves hold pressure from below, but open when a differential pressure is applied from above, allowing safe killing of the well without hydraulic control if unlatched. Lubricator Valve The lubricator valve is run one stand of tubing below the surface test tree. This valve eliminates the need to have a long lubricator to accommodate wireline tools above the surface test tree swab valve. It also acts as a safety device when, in the event of a gas escape at surface, it can prevent the full unloading of the contents in the landing string after closing of the SSTT. The lubricator valve is hydraulic operated through a second umbilical line and should be either a fail closed or; fail-in-position valve. When closed it will contain pressure from both above and below 3.4.6.

Deep Water Tools Retainer Valve The retainer valve is installed immediately above the SSTT on tests in extremely deep waters to prevent large volumes of well fluids leaking into the sea in the event of a disconnect. It is hydraulic operated and must be a fail-open or fail-in-position valve. When closed it will contain pressure from both above and below. It is usually run in conjunction with a deep water SSTT described below.

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Deep Water SSTT As exploration moves into deeper and remote Subsea locations, the use of dynamic positioning vessels require much faster SSTT unlatching than that available with the normal hydraulic system on an SSTT. The slow actuation is due to hydraulic lag time when bleeding off the control line against friction and the hydrostatic head of the control fluid. This is overcome by use of the deepwater SSTT which has an Electro-Hydraulic control system. The Hydraulic Deep Water Actuator is a fast response controller for the deepwater SSTT and retainer valve. This system uses hydraulic power from accumulators on the tree controlled electrically from surface (MUX). The fluid is vented into the annulus or an atmospheric tank to reduce the lag time and reducing closure time to seconds. If a programme required deepwater test tools, the tool operating procedures would be included in the test programme. 3.4.7.

Downhole Pressure Recording The complete sequence of events are recorded by bottom-hole pressure gauges and some flow data may also be recorded on surface read-out systems. The gauges record the events from initial running of the test string to well kill and retrieval procedures although, with the modern type gauges, they may be programmed to ‘sleep’ while the string is being installed as it wastes memory. However, with the large memory electronic gauges on the market today, this is not necessary as they have sufficient memory to record at fast intervals throughout even long term tests without running out of memory. The problem then is to dump or ignore data points which are not relevant to data gathering. Other gauges, termed ‘smart’ gauges can be programmed to collect data at moderate time intervals until they detect a quick pressure change, such as opening or shutting in the well, when they change to very short time intervals where this facility is required.

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WELL PRODUCTION TEST OBJECTIVES The main objective of well production varies from simple determination of the amount and type of fluids produced to sophisticated transient pressure determinations of reservoir parameters and hetrogenities. In short, well tests are tools which can be used to help establish the condition of production or injection wells. Engineers need to make themselves familiar with the various test procedures and know their advantages and limitations in order for them to fully utilise them to optimise the design of completions. Well production tests may be classified as follows: • • •

Periodic Productivity or Deliverability Transient Pressure.

Descriptions of some of these tests are described earlier in this section. Periodic production tests have the purpose of determining the relative quantities of oil, gas and water produced under normal producing conditions. They serve as an aid in well and reservoir operation and meeting legal and regulatory requirements. Productivity or deliverability tests are usually performed on initial completion, or recompletion, to determine the capability of the well under various degrees of pressure drawdown. Results may set production allowables, aid in selections of well completion methods and design of artificial lift systems and production facilities. Transient pressure tests require a higher degree of sophistication and are used to determine formation damage or stimulation related to an individual well, or reservoir parameters such as permeability, pressure, volume and hetrogenities. 3.5.1.

Periodic Tests Production tests are carried out routinely to physically measure oil, gas and water produced by individual wells under normal producing conditions. From the well and reservoir viewpoint, they provide periodic physical well conditions where unexpected changes such as extraneous water or gas production may highlight well or reservoir problems. Abnormal production declines may also indicate artificial lift problems, sand build-up, scale build-up in perforations, etc. On oil wells, results are reported as oil production rate, gas-oil ratio and water oil ratio as a percentage of water in the total liquid stream. Accuracy in measurement, with careful recording of the conditions is essential. Choke size, tubing pressures, casing pressure, details of artificial lift system operation and all other effects on the well producing capability should be recorded. Potential production problems should be recognised in order that they can be properly handled such as emulsions, security of power fluid or gas lift gas supply, etc. It is important that the well is produced at its normal conditions as flow rate will vary the relative quantities of oil, gas and water. On gas wells, routine are less common as each well normally has individual measuring capability. Gas production is reported as well as condensate and water. Similar to oil wells, the wells must be produced at the normal rates.

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Productivity Or Deliverability Tests This test is different from the periodic test in that the liquid flow performance can be determined empirically using measured flow rates at varying bottom-hole pressure drawdowns and they do not rely on mathematical descriptions of the flow process. With a limited number of measurements, they permit prediction of what a well could produce at other pressure drawdowns. This is then used to predict the PI (Refer to Section 2.4.1) and are successfully applied to non-Darcy conditions. They do not permit calculation of formation permeability or the degree of abnormal flow restrictions (formation damage) near the wellbore. They do, however include the effects of formation damage, therefore can be used as an indicator of well flow conditions or a basis for simple comparison of completion effectiveness among wells in a particular reservoir. Commonly used deliverability tests for oil wells may be classified as: • • • •

Productivity Index Inflow Performance Flow-After-Flow Isochronal.

These tests are described in Section 2.4.1 or in Section 3.4.1 above. Gas well deliverability tests are designed to establish AOFP. Termed multi-point backpressure tests, they can be classified as: • •

Flow-After-Flow Isochronal.

These tests are described in Section 2.4.1 or in Section 3.4.1 above. 3.5.3.

Transient Tests Radial Flow Characteristics Flow from reservoirs are characterised as transient, pseudo-steady state or steady state flow, depending on whether the pressure response initiated by opening the well had reached the drainage area boundary and on the type of boundary. Transient flow occurs when the well is initially opened or has a significant rate change, and is a result of the pressure disturbance moving out towards the outer boundary of the drainage area. During this the production conditions at the wellbore change rapidly and the BHPF, pwf, decreases exponentially with time. Most DSTs and many production tests are conducted under transient flow conditions and consequently the observed productivity will often appear greater than that seen in long term production. This means that corrections need to made to compensate for transient flow behaviour as well as for skin effects.

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When the flow reaches the outer boundary, flow becomes steady state or pseudo- steady state. If the boundary is a constant pressure boundary, then PR will not alter with time and is termed steady state. However if it is a no-flow boundary, then PR will decline purely as a result of depletion and the flow is then termed pseudo-steady state. When the BHFP appears to be constant or declining slowly proportionally with time, the well is stabilised and pseudo-steady state flow equations can be used to predict the long term deliverability of a well. Transient pressure tests are classified as: • • • • •

Pressure Build-up Pressure Drawdown Multiple Rate Injectivity or Fall-off Multiple Well Interference.

Each type presents certain advantages and limitations and factors which are important for reasonable results. Transient pressure testing and calculation procedures for oil wells are particularly well covered in SPE Monograph No. 5 - Advances in Well Test Analysis. Pressure Build-Up Tests Pressure build-up tests are described earlier in Section 3.4.1 - DST tests. Pressure Drawdown Testing Pressure drawdown tests have advantages over pressure build-up tests, production continues as the test is being carried out, and an estimate can be made of the reservoir volume in communication with the wellbore. Therefore, the ‘Reservoir Limit Test’ can be used to estimate if there is sufficient hydrocarbons in place to justify additional wells in a new reservoir. Multiple Rate Testing Pressure build-up or drawdown tests require a constant flow rate which is sometimes difficult to achieve over a long period of time. Multiple rate analysis can be applied to several flow situations, e.g. uncontrolled variable rates, a series of constant rates or constant bottom-hole pressure with continually changing flow rate. Multiple rate tests have the advantage of providing transient test data without the need for well shut-in. They minimise wellbore storage effects and phase segregation effects so provide good results where build-up or drawdown tests would not. Accurate flow rate and pressure measurement is essential and more critical than on buildup or drawdown tests. The rate changes must be significant enough to effect the transient pressure behaviour. The analysis procedure is direct and simple but computations are more troublesome and are often conducted by computer software.

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Injection Well Tests Injection well transient testing is basically simple provide the mobility of the injected fluids is similar to the in-situ fluids. The injectivity parallels the drawdown test and a pressure fall-off test parallels the build-up test. Calculation of reservoir characteristics is similar. A stepped rate injectivity test can be carried out to estimate fracture pressure in an injection well which is useful in tertiary flood applications to avoid accidental injection of expensive fluid into uncontrolled fractures. Interference Tests (multiple well testing) In interference testing, a long duration rate change in one well creates a pressure change in an observation well that is related to reservoir characteristics. A pulse test is an interference test that provides data by changing production rate in a cyclic manner to produce short term pressure pulses which are measured in the observation well(s). The responses may be very small, therefore, accurate pressure monitoring devices are required. Using computers the data can be analysed to give a description of the variation in reservoir properties according to location. Vertical pulse testing may indicate vertical formation continuity. Orientation and length of vertical fractures may be estimated through pulse testing and reservoir simulation techniques.

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DRILLING CONSIDERATIONS These are primarily the responsibility of drilling engineering, however the production department provide the design parameters to the drilling engineers.

4.1.

CASING DESIGN Refer to the Drilling Design and Casing Design Manuals for all casing design policies and criteria. These manuals provide the policies and design procedures for both exploration and development wells.

4.1.1.

Casing Profile The surface and intermediate casings are designed to provide well control and borehole stability during the drilling operation. The production casing is the string, or combination of strings, through which the well will be completed and controlled throughout its life. The production casing and its cement isolates the producing intervals to facilitate reservoir control, anchor the completion equipment and act as a safety barrier to the uncontrolled emission of hydrocarbons. The production casing is usually: • •

A full string of pipe cemented at TD. A drilled through casing and liner.

In highly productive wells, e.g. offshore, the production casing size may be swedged to accommodate larger tubing and completion equipment (i.e. TRSSV’s with control line) near surface or a hot string of isolated pipe. This larger tubing reduces friction losses. The size of the production casing is primarily dictated to accommodate the optimum size of completion tubing and equipment, and/or artificial lift systems. However, as is obvious in deep high pressure wells, there is a limit to the size of production casing which can be provided. In low rate and deep land wells, production casing sizes are typically 7ins or 1 3 5 5 /2ins. In high rate and offshore wells, 10 /4ins, 9 /8ins and 7ins are the common sizes (Refer to the Casing Design Manual). The decision whether to run a liner or not primarily lies with the drilling engineer however the impact of the completion needs to thoroughly considered. If there were a choice, the completions engineer would always prefer the largest casing possible to provide the flexibility in well interventions, workovers and re-completions with artificial lift, etc. However today, the popularity of the mono-bore completion, where a large size tubing mates to a similar size liner utilising a PBR or similar type system, it is a completion design parameter. This is a design which provides the greatest flexibility to live well intervention operations as the completion is full bore allowing regular tools to be run and used in the sump area eliminating the use of through-tubing devices. This gives live well interventions much more scope to conduct stimulation, plugging back, straddle packing-off gassed out zones, etc. which may have required a workover in previous times. figure 4.a shows these various casing profile options.

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Figure 4.A - Casing Schemes and Terminology 4.1.2.

Casing Specifications Design criteria and casing specifications are fully described in the ‘Casing Design Manual’. Specifically with regard to metallurgy, it is Eni-Agip’s policy to use standard service production casing where there is a casing tubing annulus as the tubing is designed for the well environment and isolates the production casing. However, production casing or liner below the production packer or liner hanger PBR system, will have similar specification to the tubing in order to combat corrosion from produced fluids. The crossover between the two different materials must be selected in order that there is no localised erosion. Casing exposed to H2S will have a specification in accordance to NACE MR01-75. Casing above the packer is exposed to the completion or packer fluid which must be chemically dosed to prevent any corrosion although, in general, only a biocide and possibly corrosion inhibitor needs to be added.

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Casing Connections Where an annulus is to be used as a production conduit for gas production, injection or gas lift supply, a premium thread connection should be used to reduce the risk of leakage especially if the pressure is above circa 1,250psi. This is due to the poor performance of the API Buttress Thread. Some operators specify premium connections if the wellhead pressure is to be above 5,000psi. The main problem in casing design of producing wells over exploration wells is the increased temperature. Usually production casing is held in tension but this may not be adequate enough in high temperature and thermal wells to prevent buckling. An overpull is often required especially if the casing is not cemented into the previous shoe.

4.2.

WELL DEVIATION SURVEYS A well directional survey must be carried out to ensure the tolerances for well deviation and doglegs have not been exceeded as the installation of the completion is sensitive to angle and getting fairly large diameter tubing through casing doglegs as well as placing extreme bending loads on the tubing. Refer to the ‘Directional Control and Surveying Procedures Manual’ and the ‘Casing Design Manual’. Any anomalies found in the deviation survey needs to be communicated to the completion engineer to ensure that all potential problems are analysed and will not impede the completion of the well. Although the drilling of highly deviated and horizontal wells is now commonplace it should o be noted that in wells above 70 deviation, there are problems with logging, cementing, gravel packing and the completion process as wireline cannot be used above this limit. Completion tools or equipment operated by different methods must be adopted. To help overcome these problems, many operators drill ‘S’ shaped profiles with drop off through the pay zone for critical wells, however this does not satisfy all situations. The method of drilling horizontal wells also needs to be considered by the drilling engineer as the turning radius will be dependant upon the completion method employed. For instance, the turning radius for an open hole or liner may be short but a long radius is required for gravel packing or installation of pre-packed screens.

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CASING CEMENTING CONSIDERATIONS The primary function of the cement around the production casing is to isolate individual formations to provide selectivity, prevent movement of formation fluids along the well path for reservoir control, and to isolate higher weaker formations from well pressures. The cement also acts to support and protect the casing from buckling, eccentric loading, excessive movement due to pressure or temperature and external corrosion.

4.3.1.

Production Casing Cementing The minimum cement column height requirements will depend upon local regulations, operating conditions, temperatures, formation properties, fluid properties and pressures. The cement column should extend well past (circa 500m) above the highest pay zone but also cover aquifers or any other potential producing zones. A minimum lap of 100m is normal. Many operators prefer to cement up inside the previous casing shoe to provide even greater support and protection, however this is not possible in high rate offshore wells where temperature increase in the casing/tubing annulus on the trapped fluids causes pressure which cannot be bled off at surface, therefore is allowed to bleed off at the casing shoe. Thermal wells are normally cemented to surface to avoid this problem. A cement job which does not successfully flush out the drilling fluid in front of the cement and, if there is poor bonding between the outside of the pipe and the cement, and bonding between the cement and the formation, channelling and micro-annuli may be formed which are paths through which the formation fluids can flow. This problem can be alleviated by thorough planning, using a good fluids programme and adopting good operating procedures. The main problems associated with primary cementing are: • • • • • • •

Channelling of the cement and bypassing of mud due to pipe eccentricity and poor fluid rheology. Failure to cement washouts. Poor formation bonding due to lack of mud cake removal. Poor cement procedure leading to gas entry or cross flow. o Cement strength loss due to high temperatures (<230 F) when using normal Portland cement. Cement dehydration opposite high temperature zones. Dissolution of evaporites by the cement.

In general, the list of recommendations given below will help improve the success of zonal isolation: • • • • • •

Drill the hole within gauge. Condition the mud correctly. Use a 500ft low viscosity spacer with surfactant if required. Use a thin slurry at the front end. Use cement with an API high temperature/high pressure fluid loss of less than 3 3 200cm /30 min for high permeability oil wells and 50cm /30min for gas wells. Use the highest practical displacement velocities.

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Design the programme so as the cement has a minimum contact time of 4 mins at all points where zonal isolation is needed. The cement column should extend 1,200ft above the top of the pay zone. Pipe reciprocation should be used or otherwise rotation. Centralise the casing in the pay zone. Ensure quality control of the cement formulation is strict. Use batch mixing whenever possible.

Production Casing Cement Evaluation To ensure that the cement programme has been successfully isolated the formation/casing, formation/liner or casing/liner annulus, the quality of the cement should be evaluated. This is carried out by running a cement bond log (CBL-VDL) which is an acoustic device that looks for channelling. However, the tool averages the condition around the circumference of the casing and sometimes fails to detect small channels. A more recent tool is the Schlumberger CET, which uses eight helically mounted sensors to scan the cement and provides a measurement of the compressive strength which should in theory give a better detection. Generally there is ambivalence shown towards the results of cement bond evaluation logs and unless they show extremely poor conditions, they tend to be ignored especially as repair of cement jobs is very difficult to conduct successfully.

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WELL COMPLETION DESIGN The aim of this section is now to develop the structure of the completion based on the work carried out according to the previous sections. This means that the SOR must be established, the conceptual designs have been developed and the optimum well performance determined. The completion structure and procedures, that satisfy the above, now need to be developed. However this cannot be carried out in isolation as well servicing and workover philosophies as well as the completion installation process need to be considered. To enable this process, it is necessary to describe the basic architectural components of a completion, particularly: • • •

Reservoir and wellbore interface. Casing and tubing interface. Tubing and wellhead interface.

Refer to figure 5.a The solutions adopted will vary according on the well objectives, environment, location, artificial lift method (if applicable), anticipated well problems and cost. Although the tools are available to provide the most complex completions to solve severe production or mechanical problems and meet the specific objectives, it should never be forgotten that, in principle, completions should be kept as simple in design as possible to minimise the installation risks and costs.

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Figure 5.A - Completion Design Interface Classification Options

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5.1.

FACTORS INFLUENCING COMPLETION DESIGN

5.1.1.

Reservoir Considerations

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Production Zone Isolation Consideration of reservoir management and regulatory requirements will determine the zonal isolation in thick pay zones (<30m) or multiple-zone completions. Special attention must be given to layers with great in permeability variations to determine differential depletion. With zones of have significant different inflow performance characteristics, then it may be more economic to segregate production. This can be achieved by drilling a well into each zone which is extremely costly, or as more likely, by using a multiple-string completion. Wells with gas cap or water drive reservoirs which need to be produced at controlled rates may also be candidates for a multiple completion. The downside of using multiple completions is there complexity, cost and installation. Distance From Fluid Contacts The distance of producing interval from fluid contacts may influence the offtake rate and the perforating policy. It is obviously economically attractive to perforate high permeable sections close to fluid contacts, however for the short term gain there may be increased penalties later with increased gas or water production which may need to be plugged off by a well intervention. These aspects need to be considered as does perforating the lower sections in downdip wells in flank and bottom water drive reservoirs. The effects of partial peforating need to be considered on the well IPR. Secondary Targets Potential secondary or re-completion targets need to be identified and included in the SOR because if they are not considered, they may be inadvertently isolated behind a liner lap or shoe track. They should be treated as a normal pay zone which will be left unperforated. Minimum Zone Separation The main cementing service companies are able to provide information on the minimum separation by good cement between zones for effective hydraulic under differential depletion conditions. A guideline chart for recommended isolation depth is shown in Fig figure 5.b below. If fracture stimulation is planned the separation distance is approximately three times greater. The effect of bridge plug setting and completion equipment lengths on zonal isolation must be considered as they may demand longer separation intervals, e.g. between production packers, etc.

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Figure 5.B - Guideline for Length of Cemented Interval Required for Zonal Isolation Interval Length The interval length should be determined by reservoir requirements as perforating lengths can be adjusted to suit. Casing guns standard perforating lengths are 5, 10 and 15ft and through tubing guns 20, 30 and 40ft, however one (or more sections) can be partially loaded. Wireline guns are run and fired sequentially therefore only the first perforations can be carried out with a static underbalance. To create an underbalance for other runs, the well needs to flowed which carries a risk of the guns being ‘blown’ up the hole. The use of tubing conveyed means that great lengths can be installed and fired simultaneously, and underbalanced if desired, although deploying and retrieving these long lengths may impact on safety and needs use of a safe deployment method. This is particularly useful on perforated horizontal wells.

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Mechanical Considerations The main mechanical influence on completion design is the casing profile and deviation discussed previously in sections 4.1 and 4.2. It is essential that sufficient clearance is available to allow the completion to fit comfortably inside the casing profile. With completions large tubing sizes, this may mean running of a tapered casing string to accommodate the TRSV and control line. To this end it is important to carry out the procedures to prepare the well by cleaning it and displacing to clean completion fluids and checking the internal drift. Entry into liner laps in high angles are also problematic, especially when running the completion from a moving floater so consideration needs to be given to the procedure or by using an automatic mule shoe. The type of production packer selected is dependent upon its application and installation method due to hole angle, whether it is single trip, etc.

5.1.3.

Safety Considerations Safety of the personnel and well site installation are paramount in completion design and the completion procedures. Whenever possible and economical, perforated completions should be used over open hole for well control as the casing, once it is tested, is a mechanical barrier which is safer for BOP removal. Modern compact or high performance wellheads are preferred over the traditional spool systems as the completion may be installed with out BOP removal (Refer to the ‘Drilling Design Manual’). Downhole packers in the completion string which anchor the tubing are barriers used to protect the annulus from well pressures and corrosion from well fluids although operationally they also isolate gas lift gas or pump power fluids from formation pressures in gas lift and pump completions. Refer to section 8.1 for the Eni-Agip Company policy on the use of packers. Downhole safety valves are installed as per the En-Agip company policy given in section 8.2.1.

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RESERVOIR-WELLBORE INTERFACE There are three reservoir-wellbore interface options which can be further classified into seven major alternatives in completion architecture (Refer to figure 5.a):

5.2.1.

• •

Open hole completions Uncemented liner completions. Slotted pipe Wire wrapped screens Open hole gravel packs

•

Perforated completions. Standard perforated Fracture Stimulation Cased hole gravel packs

Open Hole Completions Their use is predominately in thick carbonate or hard sandstone reservoirs that produce from fracture systems or thin permeable streaks which are difficult to identify on logs and are easily damaged by drilling and cementing operations. They maximise the fracture intersections and inflow potential due to the large surface area if drilling and completion damage is avoided. However they provide little or no selectivity in reservoir management to reduce unwanted water or gas production. An open hole completions can subsequently be converted to a liner completion to overcome the selectivity problem. Often referred to as a ‘barefoot’ completions, the method of completion entails drilling down to a depth just above the producing formation and setting the production casing. A hole is now drilled through the formation exposing it to the wellbore. The well is now completed with no casing set across the formation (Refer to figure 5.c). The decision process depends on four key issues: • • • •

Is there a risk of causing damage to well productivity with a cased and perforated completion ? Is zonal selectivity required ? Is fracture stimulation required ? Is there any potential sand production ?

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Figure 5.C - Open Hole and Uncemented Liner Interface Options 5.2.2.

Uncemented Liner Completions Uncemented liners are used to overcome production problems associated with open hole completions and to extend their application to other types of formations. The formation is supported by a either a slotted liner, sand screen or is gravel packed (Refer to figure 5.c). Although they have some advantages over open hole, they still have the same selectivity and undesired fluid problems. The selection process depends on four key issues is the same as for open hole completions: • • • •

Is there a risk of causing damage to well productivity with a cased and perforated completion ? Is zonal selectivity required ? Is fracture stimulation required ? Is there any potential sand production ?

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If a slotted liner or plain screen is to be used, a designer must also consider: • •

• • •

Whether to use the more expensive and finer wire wrapped screen or slotted pipe. Slot width requirement which is dependent on the sand size and stability, fluid viscosity and control objectives. A slot width that would retain the coarsest 10% of the sand is common practice in heavy oil wells with coarser slots for light oil wells, and finer slots or pre-packed screens for filtering and for uniform sized sands. Clearance required for washover (1 - 1.5ins on OD) and whether centralisers should be expandable, or millable, solid type. The location of the packer and packer tailpipe. Is gravel packing more suitable alternative ?

For open hole gravel packs, the following additional issues need to be considered: • • • •

Loss circulation control during under-reaming and tripping, and how the LCM can be subsequently removed before gravel packing. The stability of the hole during under-reaming and the limitations this may impose on hole angle and screen length. Gravel pack design with regard to grain size, length of blank pipe, volumes, reserve volume, etc. Type of gravel packer and will it double as the production packer ?

Slotted Liner This type of completion entails a liner with flow slots machined throughout its length installed below the production casing. The slot widths can range between 0.254 - 1.016mm. A slotted liner is used where there is a risk of wellbore instability to maintain a bore through the formation which otherwise might collapse and plug off all production. It also helps in liquid lift due to the smaller flow area. Wire Wrapped Screen A plain wire wrapped screen is used either as a simple filter to strain out small amounts of intermittently produced sand from a relatively stable formation or as a sand retention screen where high permeability, coarse sands would readily flow onto the screen forming a rubble zone. External Gravel pack An open hole gravel pack is used where the sands are too fine or abrasive for a plain screen. The open hole is under-reamed to remove drilling damage and to create a larger annulus for the filter sized gravel to pack against the formation wall. When properly installed, it is the most effective sand control measure for weak sandstones and unconsolidated rocks, however carries more risk than a cased hole gravel pack.

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Perforated Completions This type of completions are the most common world-wide due to the selectivity, flexibility, lower costs, increased safety and convenience that they provide. There are three subdivisions, standard, fracture stimulation and cased hole gravel pack (Refer to figure 5.d). The key issues in cased hole completion design are: • • • •

Perforated interval selection, gun type, shot density, underbalance or overbalance, and perforating method, i.e. casing guns, through tubing guns or TCP. Completion fluids programme selection with regard to fluid quality and formation damage. Type of formation and if special perforating techniques are required, e.g. high shot density, ultra deep penetration or stimulation treatments. Effective zonal isolation due to cement quality and distance between zones.

Standard Perforated Casing Completions These are used when the rock is reasonably stable and permeable. Deep penetrating perforating charges are generally used especially in hard rock, with the shot density dependent upon the vertical permeability and layer frequency, the deliverability requirements and method of perforating. The deep penetrating charges are desired to perforate through the damage zone cause by the drilling or completing process. Perforating underbalance may also improved perforation clean-up. Fracture Stimulation Fracture stimulation is used to increase the effective sandface area and to provide a high permeability flow path to the wellbore increasing the IPR from low permeability rocks (<25md). The risk in fracture stimulation is that the fractures will more than likely not be contained within the pay zone and the casing cementing programme completion equipment rating, etc. would need to be designed with the additional loading of the stimulation operation. Cased Hole Gravel Pack Cased hole gravel pack completions are used to control sand production in perforated completions. Unlike the open hole gravel pack, the cased hole gravel is placed between the cased hole and the sand screen, ideally, with the gravel forced into the perforations holding the formation sand in place. Since the gravel has an finite permeability, a large flow area must be achieved by using ‘big hole’ charges with the maximum shot density (dependent on gun size).

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Figure 5.D - Perforated Casing Interface Options 5.2.4.

Multi-Zone Completions There are four main methods of completing multi-zone wells (Refer to figure 5.e): •

Commingled production allowing all zones to produce together.

•

Sequential zonal production through live well intervention methods by re-completion.

•

Single string multi-zone segregated production by initial (or eventual) commingling by sequential (or alternating) production.

•

Multi-string (dual) multi-zone segregated production using parallel strings using concentric strings.

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Commingled Production Commingled production is only allowable is limited instances where there are no reservoir management problems and regulatory rules allow. Sequential Zonal Production Due to its simplicity and ease of installation, completion designers prefer to use single string/single zone completion methods for mutli-zone situations. This preference is subject, however, to economics, reservoir management and regulatory requirements. In this method, the zones are depleted from the bottom upwards and temporarily suspended or abandoned sequentially and then the next higher zone completed. If zones are close together, the initial completion can be installed to allow plugging and perforating of each zone by well intervention methods, however there is a trade off in that flow efficiency of the deeper zones and depth access for artificial lift and well killing will be compromised. An option is to conduct a workover pulling the tubing and re-completing by moving the packer depth upwards. Single String Multi-Zone Production These provide easy methods of bring on other fresh zones when the first zone experiences production problems. They may also be used for reservoir management, by allowing commingling or individual section production at different stages in the wells life in order to maximise the full potential of the reservoir. Downhole chokes or regulators can be installed to control flow from each zone when commingling to prevent cross-flow, reduce excessive gas, etc. Dual String Multi-Zone Production Dual string multi-zone completions are often used offshore or on stacked reservoirs where the production rate is per zone is limited by inflow performance and the previous methods described above would be uneconomic. They can often double an individual wells productivity for a reasonably low cost increment. Either parallel strings or concentric strings can be used. Concentric strings may yield higher flow capability but obviously no downhole safety valve can be installed in the outer tubing. Some operators use the casing tubing annulus as another flow conduit but this is subject to individual operator philosophy and regulatory rules dictating. If artificial lift is required parallel strings would normally be needed. Triple strings and indeed quadruple string have been used in the past, but generally they are not economic as they are too restrictive of well capacity.

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Figure 5.E - Multi-Zone Completions

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CASING-TUBING INTERFACE There are three main casing-tubing interface options which have six sub-divisions (Refer to figure 5.f): •

Packerless completions Anchored Unanchored Tubingless.

•

Packer Completions Shallow set Deep set.

•

PBR Completions Liner hanger.

Packers and PBRs are required to provide a seal between the tubing and production casing or liner for the following reasons: • • • • • • • • •

To isolate the casing-tubing annulus from well fluids and pressure acting as a barrier on the annulus side. To prevent heading in the annulus improving flow conditions. Prevent annulus corrosion from well fluids. To allow the annulus to be used for supplying artificial lift fluids or injection of inhibitors. To allow the annulus to be used for production (if permitted). To isolate liner laps or casing leaks. To anchor the tubing if no tubing movement is desired. To facilitate well operations through having wireline nipples in a tailpipe, e.g. well plugging, BHP gauge positioning, etc. To protect formations from damage from well intervention or workover fluids by plugging in the tailpipe.

Some onshore low pressure wells are completed without a packer or liner PBR as the risk of damage to the wellhead, hence the risk of injury to personnel and pollution of the environment, is low. This has both advantages and disadvantages. There is one barrier less on the annulus side and the casing may be exposed to corrosive well fluids and the well pressure even if it is low and some operators do not allow this practice. On the other hand, on pump completions it is useful for venting off gas. It is essential for plunger lift completions which uses annulus gas as its energy source for unloading liquids. Tubingless completions, i.e. wells which use a small diameter casing or a tubing as the production casing, offers serious well control problems as there is no downhole safety at all. These are used on low rate, low pressure wells but are not allowed by most operating companies.

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Anchored tubing completions are used on rod pumpers to keep the tubing in tension so that the reciprocation of the rods does not cause buckling on the upstroke and stretch on the downstroke unless the well is shallow and annulus clearance is small. Packer completions are the most popular due to their flexibility in the options in which they are available and their ability to be installed in an exact position at any desired depth compared to the liner PBR. The liner PBR completion offers a larger through bore than a packer option and, therefore are used in high rate wells and mono-bore completions where full bore access is gained to he formation. The liner PBR interface should not be confused with the packer PBR system which although is exactly the same in basic design, is used for packer-tubing sealing and catering for tubing movement.

Figure 5.F - Casing-Tubing Interfaces

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Packer Applications Packer application with regard to completion design is addressed in this section as there are some basic features which affect the completion architecture. Although there are many varieties of packers available, there are three basic types used in completion designs: • • •

Permanent Retrievable Permanent Retrievable.

Eni-Agip do not have any particular policy to the type of packer system to be used in a particular situation due to the wide range of packers available and changing technology but do operate a packer qualification system to ensure that any packer used meets with specific criteria. The packer qualification system is specified in STAP-M-1-M-5010. Retrievable Packer Systems The definition of a retrievable packer is that it is installed and retrieved on the completion tubing. They have advantages in that they can be installed in high angle wells although their operating differential pressure rating, temperature rating and bore size are less than equivalent permanent packers. It is important that designers fully consider the effects of pressure and tubing stresses on these packer systems and associated packer-tubing connections. Their packing element systems are also more sensitive to well fluids as they are more complex due to their ability to be retrieved but after redressing they can be reused. Retrievable packers tend to be used for the following applications: • • • •

Completions which have relative short life span. Where there is likely to be workovers requiring full bore access. Multi-zone completions for zonal segregation. In relatively mild well conditions.

Retrievable packer setting mechanisms are by: • • • •

Tubing tension Tubing compression Hydraulic pressure Tubing rotation.

Tension or compression set packers are very sensitive to tubing movement and are rarely used nowadays owing to the benefits and variety of other retrievable packers available.

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Permanent Packer Systems The definition of a permanent packer is that it is retrieved from the well by milling. Permanent packers have high differential pressure and temperature ratings and larger bores. They have many options of both tailpipe and packer-tubing attachments to cater for a large range of applications such as: • • • • •

Severe or hostile operating conditions with differential pressures > 5,000psi and o temperatures in excess of 300 F and high stresses. Long life completions. Where workovers are expected to be above the packer, hence not requiring its removal which is costly. Where workovers are expected to be above the packer and the packer tailpipe can be used for plugging the well and isolating foreign fluids from the formation. Providing large bore for high rate wells.

Permanent packer setting mechanisms are by: • • • •

Wireline explosive charge setting tool. Tubing tension. Hydraulic pressure by workstring setting tool or on the completion string. Tubing rotation.

Permanent Retrievable Packer Systems Permanent retrievable packers are a hybrid of the permanent style packer designed to be retrieved on a workstring without milling. They offer similar performances as permanent packers but generally have smaller bores. All the packers above can be equipped with tailpipes to accommodate wireline downhole tools such as plugs, standing valves, BHP gauges, etc. 5.3.2.

Packer-Tubing Interfaces Tubing can be interfaced with packers through three basic options: •

Fixed By threaded connection to the packer mandrel as with retrievable packers. Snap latch requiring an overpull to release By an anchor latch system to a permanent packer.

•

Free moving Seal unit in a packer bore. Seal unit in a PBR attached to the packer. Travel joint. ELTSR.

•

Limited movement Seal unit set down in a packer bore allowing upward movement only. Closed PBR or ELTSR.

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Free movement or partial movement options are used when tubing movement must be catered for otherwise it may be over-stressed due to tubing forces found through the stress analysis (Refer to section 7). However, sometimes they suffer from premature seal failure due to being dynamic seals and if the material type has not been correctly selected for the environment and pressure differentials. To help prevent seal failure, seal units can be shear pinned in a mid open or closed position to prevent seal movement until the stresses in the tubing reach a predetermined level. The selected packer-tubing interface has a significant effect on the completion architecture especially with regard to installation procedure, well kill method, stimulation treatment and type of hanger system. The most popular packer systems are those which have ‘one trip’ installation saving extra trips by workstring or wireline to install the packer before running the completion tubing. 5.3.3.

Annulus Circulation Communication between the tubing and annulus on packer type completions is consider to be beneficial to efficient well killing, maintaining a fluid barrier in the annulus, circulating kill fluid before workovers or circulating in underbalance fluids well kick off. This is the same reasons for installing kill strings in packerless completions. Circulating devices, typically sliding sleeves or sliding side doors (SSDs) installed above the top packers, are used for this purpose but they have traditionally been a weak link in design when seals material was not suited to the well conditions. This would require a workover to replace the sleeve so other devices such as SPMs are used as the seals can be recovered and replaced by wireline methods. Some operators recommend that no circulation device be used which limits the flexibility of the completion and requires a tubing punch to be used for circulation before workovers. If a circulating device is undesired but the option is to kill the well by circulation rather than bullheading, a single shot shear kill valve can be installed which is operated by annulus pressure. Annulus circulation is used for: • • • • •

Displace completion fluids and Kick-Off wells. Isolation/opening of producing intervals in single selective or dual selective completions. Well killing in tight formations where bullheading might be difficult. Installation of hydraulic pumps The SSD type circulating valves are normally equipped with a landing nipple profile in the upper sub to allow installation of a straddle to stop leaks or for normal wireline nipple uses.

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TUBING-WELLHEAD INTERFACE The wellhead carries the casing and completion loads which is transferred to the ground through the surface casing. It also isolates the top of the tubing-casing annulus, mates and seals with the Xmas tree and provides annulus access to all the annuli. It consists of an assembly made up of casing head spools, tubing hanger/spool and Xmas tree. The casing head and tubing hanger spools are now commonly replaced by compact or unitised wellheads (Refer to the ‘Drilling Design Manual’) to reduce height and improve safety as there are less BOP removals for spool installations. Wellhead specifications are laid out in API Specification 6A and are rated by: • •

Maximum working pressure according to the maximum anticipated surface pressure. Temperature operating range.

Temperature Classification

Operating Range, oF

K

-75 to 180

L

-60 to 180

M

-40 to 180

P

-20 to 180

S

0 to 150

T

0 to 180

U

0 to 250

PSL O

-20 to 250

Table 5.A - API Temperature Classifications o

Above 250 F the working pressure is de-rated against temperature (down to o 72% of rating at 650 F. • • 5.4.1.

Retained fluid rating (Refer to section 6). Product specification level PSL (Refer to API spec 6A).

Tubing Hanger Systems There are five common types of tubing hanger systems available: • • • • •

Slip and seal assemblies. Mandrel compression hangers. Ram type tension hangers. Downhole tubing hangers (e.g. annular safety system). Direct attachment to the Xmas tree (threaded).

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The main consideration in hanger selection is whether the tubing is to be placed in compression or tension and/or the number of tubings, flow or supply. Other considerations are DHSV control lines, downhole chemical injection lines, downhole electronic gauge cables and ESP cables which are terminated by stab seals, extended necks or annular ring seals. On subsea wells vertical annular access is usually required for well plugging which requires mandrel type hangers with orientation to the guide base and, hence subsea tree. Dual hanger systems also need to be orientated to mate with the dual Xmas tree. Depending on the well location, i.e. subsea, platform or land, well plugging for tree removal needs to be considered and that is usually satisfied by having a locking profile in the hanger bores, either wireline nipple profile or a back pressure thread for land wells.

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Figure 5.G - API Recommended Minimum PSL for Wellhead Equipment

1.2

1.2

1.2

1.2

1.2

DCSFSL 3

SCSO 1

DCSO 1

DCSO 2

DCSO3

21 1/4

21 1/4

21 1/4

21 1/4

21 1/4

21 1/4

2.1 2.4

5000 13 3/8 & 9 5/8

20 & 18 5/8

3000

5000

5000

5000

5000

5000

5000

5000

5000

24 1/2

20 & 18 5/8

20 & 18 5/8

20 & 18 5/8

20 & 18 5/8

20 & 18 5/8

20 & 18 5/8

2.6

2.5

2.4

2.4

2.4

2.4

2.4

2.4

2.1

5000 13 3/8 & 9 5/8

20 & 18 5/8

2.1

13 3/8 & 9 5/8

5000

Ref. nr

Btm (CSG) (in)

Max. W.P. (psi)

26 3/4

21 1/4

21 1/4

21 1/4

21 1/4

21 1/4

21 1/4

21 1/4

21 1/4

13 5/8

13 5/8

13 5/8

Btm Flange (in)

3000

5000

5000

5000

5000

5000

5000

5000

5000

5000

5000

5000

Max. W.P. (psi)

21 1/4

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

Top flange (in)

CASING HEAD SPOOL

5000

10000

5000

5000

5000

5000

5000

5000

5000

5000

5000

5000

Max. W.P. (psi)

2.5

2.3

2.2

2.2

2.1

2.1

2.1

2.2

2.1

Ref. nr

21 1/4

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

5000

10000

5000

5000

5000

5000

5000

5000

5000

Max. W.P. (psi)

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

Top flange (in)

CASING HEAD SPOOL Btm flange (in)

10000

10000

10000

10000

5000

5000

5000

10000

5000

Max. W.P. (psi)

2.3

5.2

5.5

5.4

5.4

5.3

5.2

5.1

5.1

5.1

5.1

Ref. nr

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

13 5/8

Btm Flange (in)

9

7 1/16

7 1/16

7 1/16

11

9

9

9

9

9

Top flange (in)

10000

10000

5000

5000

5000

10000

5000

5000

5000

5000

Max. W.P. (psi)

10000

13 5/8

10000

3° CASING HEAD SPOOL

10000

10000

5000

5000

5000

10000

5000

5000

5000

5000

Max. W.P. (psi)

TUBING SPOOL

6.8

6.7

6.9

6.4

6.5

6.8

6.6

6.3

6.2

6.1

Ref. nr

5000 10000

7 1/16 7 1/16

10000

5000

7 1/16

9

5000

2 x 2 3/8

2 x 2 3/8

2 x 2 3/8

3 1/2

2 x 3 1/2

2 x 2 3/8

2 x 2 3/8

5000

10000

5

3 1/2

2 7/8

Diam tbg (in)

5000

5000

5000

Max. W.P. (psi)

11

9

9

9

9

9

Diam (in)

TUBING HANGER


IDENTIFICATION CODE

STAP-P-1-M-7100

(*) Typical wellhead configuration for deep wells (po Valley)

26 3/4

1.2

DCSFSL 2

21 1/4

1.1

1.2

DCSFSL 1

13 5/8

21 1/4

1.3

MSCL 3

13 5/8

13 5/8

Top flange (in)

CASING HEAD

1.2

1.3

MSCL 2

(*)

1.3

Ref.nr

MSCL 1

AGIP CODE

Typical outlines for on-shore, off-shore single and dual completion class -A and class -B (STAP -M-1-SS-5701E)

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Table 5.B- Eni-Agip Standard Wellhead Equipment Chart

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REVISION

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4

3

2

1

20" 13 3/8" 9 5/8" 7"

WP (psi) Section 1 Section 2 Section 3 Section 4 Section 5

3K (A) 470 620 472 -

3K (B) 470 620 472 -

5K (C) 470 625 472 -

5K (D) 470 690 670 581 -

10K (E) 470 690 660 700 -

Figure 5.H - Typical Wellhead

10K (F) 510 850 700 700 --

15K (G) 510 850 700 750

15K (H) 510 850 700 750

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Figure 5.I - Typical Unitised Wellhead and Xmas Tree

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Xmas Trees The type of Xmas tree and construction are important as they have an effect on safety and cost. The important pointers for the design engineer are: • • •

•

• •

• •

Conventional composite flanged connection trees with a single master valve are the norm for land and low to moderate offshore wells. In very high pressure wells (i.e. 15,000psi) Eni-Agip normally installs an additional gate valve between the tubing spool and the Xmas tree to provide double barrier protection. A second master valve is normally required to enable repair to any of the other tree valves with two barriers in situ (the lower master valve and the tubing hanger plug). Today it is normal to have to justify only a single master valve as the upper master is usually an ESD hydraulically operated valve which is at risk of undue wear and tear. Trees for sour service or high pressure will normally have two outlets, production and kill wing sides. The kill wing is often permanently connected up to the kill line to a permanent pump or to allow quick and easy connection of a portable pump. A swab valve is an essential element to enable safe rig up of vertical well interventions by wireline, coiled tubing or snubbing services or for the BPV rod lubricator. The production wing, which is often a remote hydraulic operated valve, choke and flowline arrangement must be configured to meet with how the well is closed-in and opened up. Pressure losses of the offtake system must be considered in the well deliverability analysis (Refer to Section 2.4.3). Chemical injection points are usually available at the tree or through the hanger system for downhole. If the tree upper master valve and production wings are fully automated, the control system should be designed to close the wing valve first a few seconds before the upper master to avoid erosion or damage over a period of time to the upper master gate and seats as they are more difficult to repair.

A typical Xmas tree is shown in figure 5.i. 5.4.3.

Metal-To-Metal Seals The purpose of metal-to-metal seals is to provide enhanced sealing where it is required in particular applications. Policy Metal-to-metal seals shall be used in the applications outlined in the following sections.

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Application The following criteria is applicable to the various conditions listed in the following tables: a)

Between producing strings/casing/tubing hanger and tubing hanger seal flange.

b)

Between tubing hanger and tubing spool.

c)

On production casing or production liner.

d)

On control line connections.

These designations A, B, C and D will be used in the tables in the tables below. Oil And Gas Producers These tables apply equally to onshore and offshore wells. Sweet Service Wells (with top hole temperature less than 100°C)

9 = YES Sealing WP, psi 5,000 10,000 >10,000

8 = NO

A

B

C

D

9 9 9

8 9 9

8 8 8

9 9 9

Sweet Service Wells (with top hole temperature exceeding 100°C) Sealing WP, psi 5,000 10,000 >10,000

A

B

C

D

9 9 9

9 9 9

8 8 9

9 9 9

A

B

C

D

9 9

8 9

8 8

9 9

A

B

C

D

9 9

8 9

8 8

9 9

H2S Service Wells Sealing WP, psi 5,000 10,000 Gas Injectors Sealing WP, psi 5,000 10,000

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Water Injectors Sealing WP, psi 5,000 10,000

A

B

C

D

9 9

8 9

8 8

9 9

Artificial Lift Wells (both onshore and offshore wells) Sealing WP, psi 5,000 10,000

A

B

C

D

9 9

8(1) 9

8 8

9 9

(1) If H2S is present it will be a YES. 5.5.

FUTURE CONSIDERATIONS Built into the conceptual stage, a design life for the completion will have been established. During this process future well servicing and maintenance will also have been planned. This will have included identification of the potential reasons for well interventions or workover servicing. This will have an impact of the completion architecture and establish a philosophy. The well location and type of development has a large impact on the techniques available and cost of well servicing and maintenance optimising the completion design around the potential problems and remedial techniques is a balancing act between effectiveness and cost. As an example of this is horizontal completions selected to maximise initial well productivity, where the stand-off from the water or gas zones increases the risk of producing early unwanted fluids. In this case to the stand-off can be increased but there is a penalty in lower initial production rates. Another example is on offshore subsea fields, due to the high cost of subsea well re-entrys, well servicing should be minimised as they require a floating vessel from which to deploy the re-entry system. This means well life should be planned for the life of the field or as long as feasible (typically 7-10 years) although some unplanned problems may occur. Alternately, on an easily accessible land wells where servicing and workover methods are relatively much less costly, servicing can be conducted almost on demand. This may lend to the selection of a wireline retrievable type safety valve rather than a tubing retrievable type as in the event of failure, the valve can be replaced cheaply without requiring a workover. Well servicing or workover techniques also have an impact on the well area with regard to height and lateral space, and may be problematic on platforms where space, height and weight are at a premium.

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Stimulation If future stimulation operations are required such as fracturing, the effects of the pressures causing additional stresses on the tubing and packer need to be input and catered for in the tubing design process (Refer to Section 7). If the costs of upgrading the well tubulars to resist these stresses are prohibitive, e.g. the surface pressure would demand a higher pressure rated Xmas tree than required for production only, then straddles are sometimes utilised to keep pressure off the SCSSV and Xmas tree. It could also increase the tubing movement and alter the choice of tubing movement device and spacing out. If acid stimulations are planned, the effects on the completion materials needs to be considered or alternatively to use coiled tubing for spotting of the acid before pumping to the formation.

5.5.2.

Formation Management As the fluid interfaces move through time and unwanted fluids are produced, or as producing zones become depleted and require isolating before brining on other zones, cement squeezes and reperforating techniques are required. Also, producing zones are sometimes damaged by scale build up or movement of fines, etc. and need reperforating. If the well has been planned for these operations then the completion may have been designed to accomplish these operations without pulling of the tubing in a workover operation. A single string sequential completion may be employed where existing perforations can be isolated simply by installation of a bridge plug on wireline but often the perforations require to be squeezed off with cement (Refer to Section 5.2.4). This can be conducted by coiled tubing or snubbing services without killing the well. The next production zone can then be perforated using through tubing perforating techniques (Refer to Section 9). If a multi-zone single string selective completion design has been installed then producing zones can be closed off or opened up by wireline techniques and hence, are more flexible but have higher initial capital cost. Excessive water or gas production due to fingering which requires continuing production from lower zones can be isolated by cement squeezing or if using a monobore type completion by installing a straddle across the interval on wireline or coiled tubing methods. If multi-zone multi-string completions are installed then the individual zones can simply be closed off by shutting in the well at surface or, if there are more than one zone to a string, by opening and closing isolation sleeves. Where this problem has not been planned into the completion design a complete workover to re-complete may be required.

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Well Servicing Techniques Well servicing includes live well intervention services or major workovers to pull the tubing. Live well interventions can be conducted by: • • • •

Wireline (electric line or slickline). Coiled Tubing. Snubbing. Pumps.

Snubbing cannot be deployed from any floating installation. A specialist subsea wireline technique has been developed for subsea well interventions without using the riser re-entry system which is much quicker and less costly. Workovers can be conducted by: • • •

Workovers rigs Drilling rigs Hydraulic workover units.

Hydraulic workover cannot be deployed from any floating installation. Slickline Is probably the most widely used well servicing method and is used for: • • • • • • • • • •

Mechanical well clean out (tubing and sump) Installation and retrieval of flow controls (plugs, chokes, standing valves, gas lift valves, etc.) Tubing control (drifting) Calipering Swabbing BHP pressure and temperature monitoring Electronic memory logging Opening and closing of circulation devices Perforating Fishing.

Braided Line Braided line is used for: • •

Heavy duty wireline work (installing large heavy flow controls). Fishing (when slickline has been unsuccessful, fishing electric line).

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Electric Line Electric line is used for: • • • • • •

Logging (PLT, etc. Calipering Real time BHP surveys Perforating Packer setting Installing bridge plugs.

Coiled Tubing Coiled tubing (C/T) is used for: • • • • • • • • •

Stimulation (acidising) Cementing Cleaning out tubing and sump Gas lifting Logging (stiff wireline) Installing flow controls (wireline type tools) Milling Drilling (underbalance side tracking, multi-laterals) Fishing (generally when wireline has been unsuccessful).

Snubbing Snubbing is used for: • • • • • • •

Stimulation (acidising) Cementing Cleaning out tubing and sump Gas lifting Installing flow controls (wireline type tools) Milling Drilling (underbalance side tracking, multi-laterals).

Snubbing has found a revival with platform horizontal wells where it is used to work in long horizontal sections where C/T may not be capable.

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OPTIMISING TUBING SIZE The optimum tubing size is selected to obtain the desired offtake rates at the lowest capital and operating costs. This usually means at the maximum initial flow rate and maintaining it as long as possible, however, depending on the inflow capability (Refer to Section 2.4), it may be possible to accelerate offtake by the early installation of artificial lift. Whatever the case, the selection process inevitably involves analysis of the gross fluid deliverability and flow stability under changing reservoir conditions to confirm that the production forecast can be met and to determine when artificial lift or compression is required. A fixed flow rate, as tubing size increases, fluid velocities decrease and reduces the frictional effects. The net result should be higher production rates only if the IPR/TPC intercept remains to the right of the TPC minimum. If the PI was infinite, one increase in API tubing size would double the maximum theoretical capacity. 1

The example well #1 in figure 5.j shows that the 4 /2” tubing size should be selected to ensure the offtake exceeds the target of 8,000 to 9,000stb/d and perhaps even larger tubing could be investigated. However, at low rates, the reduced fluid velocities experienced in larger tubing increase the hydrostatic head because of slippage. This shifts the TPC minimum to a higher rate and, therefore widening the flat uncertain portion around the minimum. If the IPR curve intersects the TPCs in the region near the minimum, the optimum tubing size will be a compromise maximising flow rate and having steady producing 1 conditions. For example, using the IPR for well 2, the maximum flow rate is obtained with /2” 7 tubing but only a slight reduction in flow rate is seen if the 2 /8” tubing is selected which gives steadier and regular flow. It is generally recommended to select a tubing size such that the flowing pressure, Pwf, is greater than 1.05 of pressure minimum, pmin to ensure stability. As previously mentioned, the changing conditions over the life of the well must be considered when selecting tubing size. These changes are normally declining reservoir pressure and increasing water cut which will reduce flow rates. This trend is downwards towards cessation of flow and ,obviously the tubing selected for the start of production will not be the optimum size after some period of time. The choice at that time will be to reduce wellhead pressure, replace the tubing with a smaller size or to implement artificial lift which will have associated costs. The optimum size of tubing is clearly the size which will be most cost effective over a number of years, typically 5-8 years. Where high costs workovers are involved such as on subsea wells, the selection may be for an even longer period of time, incurring early loss of potential production. The following sub-sections describes the various factors and there effect on TPC.

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Figure 5.J - Example Tubing Sizes on Well Deliverability

Figure 5.K- Effect of Reservoir Pressure on TPC

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Reservoir Pressure As reservoir pressure declines over time, it collapses towards the origin, as illustrated in figure 5.k, leading to decreasing natural flow rates. Unstable flow conditions and eventually cessation will occur unless some other change in the system is made. In reservoirs where significant reductions in reservoir pressure are anticipated, the effect on productivity must be considered during the completion design stage to find the most cost effective method of maximising productivity, e.g. where workover costs are high to complete with smaller size tubing to ensure stability through the economic life of the well.

5.6.2.

Flowing Wellhead Pressure Any flowing wellhead pressure is actually back-pressure transmitted downhole to the bottom-hole flowing pressure, therefore reducing the potential drawdown. Also high wellhead pressures reduces the amount of free gas and compresses the remaining free gas, both which increase hydrostatic head. All of these reduce the natural flow rate of the well. The larger tubing sizes are more sensitive to changes in flowing wellhead pressure as the density factor dominates more than in smaller tubing. Again this means that smaller tuning may need to be selected instead of the ideal larger tubing to cater for anticipated changes in wellhead pressure. Changes in wellhead pressure can be attributed to slugging in the flowline, wells being produced or closed in which use the same flowline, facility malfunctions, build-up of wax, etc. This clearly shows how important the assumed wellhead pressure accuracy is in the well deliverability forecast and economics.

5.6.3.

Gas-Liquid Ratio Increasing gas-liquid ratios cause a decrease in hydrostatic head and increase in frictional pressure drop which in the early stages may actually result in increased flow rates. However, above a critical point there will be a net increase in the overall pressure drop, hence flow rates. In these circumstances the frictional effects near surface become very dominant and can be alleviated by the use of a tapered tubing string. figure 5.l shows the effect of increasing GLR.

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Figure 5.L - Effect of Increasing GLR 5.6.4.

Artificial Lift The intention of installing artificial lift is to reduce the hydrostatic head and, therefore, bottom-hole pressure. This effectively shifts the TPC downwards bringing the intersection point further towards stable flowing conditions. An example of rates which can be obtained by different artificial lift methods is illustrated in figure 5.m. Refer to section 10 for the applications and comparisons of the various methods of artificial lift.

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Figure 5.M - Examples of Artificial Lift Performance

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CORROSION A production well design should attempt to contain produced corrosive fluids within tubing. They should not be produced through the casing/tubing annulus. However, it is accepted that tubing leaks and pressured annuli are a fact of life and as such, production casing strings are considered to be subject to corrosive environments when designing casing for a well where hydrogen sulphide (H2S) or carbon dioxide (CO2) laden reservoir fluids can be expected. During the drilling phase, if there is any likelihood of a sour corrosive influx occurring, consideration should be given to setting a sour service casing string before drilling into the reservoir. The BOP stack and wellhead components must also be suitable for sour service.

6.1.

DEVELOPMENT WELLS Casing corrosion considerations for development wells can be confined to the production casing only. •

Internal corrosion The well should be designed to contain any corrosive fluids (produced or injected) within the tubing string by using premium connections. Any part of the production casing that is likely to be exposed to the corrosive environment, during routine completion/workover operations or in the event of a tubing or wellhead leak, should be designed to withstand such an environment.

•

External corrosion

Where the likelihood of external corrosion due to electrochemical activity is high and the consequences of such corrosion are serious, the production casing should be cathodically protected (either cathodically or by selecting a casing grade suitable for the expected corrosion environment). 6.2.

CONTRIBUTING FACTORS TO CORROSION Most corrosion problems which occur in oilfield production operations are due to the presence of water. Whether it may be present in large amounts or in extremely small quantities, it is necessary to the corrosion process. In the presence of water, corrosion is an electrolytic process where electrical current flows during the corrosion process. To have a flow of current, there must be a generating or voltage source in a completed electrical circuit.

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The existence, if any, of the following conditions alone, or in any combination may be a contributing factor to the initiation and perpetuation of corrosion: •

Oxygen (O2) Oxygen dissolved in water drastically increases its corrosivity potential. It can cause severe corrosion at very low concentrations of less than 1.0ppm. The solubility of oxygen in water is a function of pressure, temperature and chloride content. Oxygen is less soluble in salt water than in fresh water. Oxygen usually causes pitting in steels.

•

Hydrogen Sulphide (H2S) Hydrogen sulphide is very soluble in water and when dissolved behaves as a weak acid and usually causes pitting. Attack due to the presence of dissolved hydrogen sulphide is referred to as ‘sour’ corrosion. The combination of H2S and CO2 is more aggressive than H2S alone and is frequently found in oilfield environments. Other serious problems which may result from H2S corrosion are hydrogen blistering and sulphide stress cracking. It should be pointed out that H2S also can be generated by introduced microorganisms.

•

Carbon Dioxide (CO2) When carbon dioxide dissolves in water, it forms carbonic acid, decreases the pH of the water and increase its corrosivity. It is not as corrosive as oxygen, but usually also results in pitting. The important factors governing the solubility of carbon dioxide are pressure, temperature and composition of the water. Pressure increases the solubility to lower the pH, temperature decreases the solubility to raise the pH. Corrosion primarily caused by dissolved carbon dioxide is commonly called ‘sweet’ corrosion. Using the partial pressure of carbon dioxide as a yardstick to predict corrosion, the following relationships have been found: Partial pressure >30psi usually indicates high corrosion risk. Partial pressure 3-30psi may indicates high corrosion risk. Partial pressure <3psi generally is considered non corrosive.

•

Temperature Like most chemical reactions, corrosion rates generally increase with increasing temperature.

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Pressure Pressure affects the rates of chemical reactions and corrosion reactions are no exception. In oilfield systems, the primary importance of pressure is its effect on dissolved gases. More gas goes into solution as the pressure is increased this may in turn increase the corrosivity of the solution.

•

Velocity of fluids within the environment Stagnant or low velocity fluids usually give low corrosion rates, but pitting is more likely. Corrosion rates usually increase with velocity as the corrosion scale is removed from the casing exposing fresh metal for further corrosion. High velocities and/or the presence of suspended solids or gas bubbles can lead to erosion, corrosion, impingement or cavitation.

6.3.

FORMS OF CORROSION The following forms of corrosion are addressed in this manual: Corrosion caused by H2S (SSC) -

Corrosion caused by CO2 and Cl

Corrosion caused by combinations of H2S, CO2 and ClCorrosion in injection wells and the effects of pH and souring are not included. The procedure adopted to evaluate the corrosivity of the produced fluid and the methodology used to calculate the partial pressures of H2S and CO2 will be illustrated in the following sub-sections. 6.3.1.

Sulphide Stress Cracking (SSC) The SSC phenomenon is occurs usually at temperatures of below 80°C and with the presence of stress in the material. The H2S comes into contact with H2O which is an + essential element in this form of corrosion by freeing the H ion. Higher temperatures, e.g. above 80°C inhibit the SSC phenomenon, therefore knowledge of temperature gradients is very useful in the choice of the tubular materials since differing materials can be chosen for various depths. Evaluation of the SSC problem depends on the type of well being investigated. In gas wells, gas saturation with water will produce condensate water and therefore create the conditions for SSC. In oil wells, two separate cases need to be considered, vertical and deviated wells: a)

In vertical oil wells, generally corrosion occurs only when the water cut becomes higher than 15% which is the ‘threshold’ or commonly defined as the ‘critical level’ and it is necessary to analyse the water cut profile throughout the producing life of the well.

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b)

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In highly deviated wells (i.e. deviations >80 ), the risk of corrosion by H2S is higher since the water, even if in very small quantities, deposits on the surface of the tubulars and so the problem can be likened to the gas well case where the critical threshold for the water cut drops to 1% (WC <1%).

The following formulae are used to calculate the value of pH2S (partial pressure of H2S) in both the cases of gas (or condensate gas) wells or oil wells. Firstly, the potential for SSC occurring is evaluated by studying the water cut values combined with the type of well and deviation profile. If the conditions specified above are verified then the pH2S can be calculated. Gas Or Condensate Gas Well H2S partial pressure is calculated by: pH2S = SBHP x Y(H2S)/100

Eq. 6.A

where: SBHP = Y(H2S) = = pH2S

Static bottom-hole pressure [atm] Mole fraction of H2S Partial H2S pressure [atm]

SSC is triggered at pH2S >0.0035 atm and SBHP >4.5 atm. Oil Bearing Well The problem of SSC exists when there is wetting water; i.e.: Water cut >15% for vertical wells o Water cut >1% for horizontal or highly deviated wells (>80 ) 3 3 or if the GOR >800 Nm /m The pH2S calculation is different for undersaturated and oversaturated oil. Undersaturated Oil In an oil in which the gas remains dissolved, because the wellhead and bottom-hole pressures are higher than the bubble point pressure (Pb) at reservoir temperature, is termed undersaturated. In this case the pH2S is calculated in two ways: • •

Basic method. Material balance method.

If the quantity of H2S in gas at the bubble point pressure [mole fraction = Y(H2S)], is not known or the values obtained are not reliable, the pH2S is calculated using both methods and the higher of the two results is taken as the a reliable value. Otherwise the basic method is used.

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Basic Method This method is used, without comparison with the other method, when the H2S value in the separated gas at bubble point conditions is known and is reliable or if Y(H2S), molar fraction in the separated gas at bubble point pressure (Pb) is higher than 2%. The pH2S is calculated by: pH2S = Pb x Y(H2S)/100

Eq. 6.B

where: Pb = Y(H2S) = pH2S

=

Bubble point pressure at reservoir temperature [atm] Mole fraction in the separated gas at bubble point (from PVT data if extrapolated) Partial H2S pressure [atm]

Material Balance Method This method is used when data from production testing is available and/or when the quantity of H2S is very small (<2,000ppm) and the water cut value from is lower than 5% (this method cannot be used when the WC values are higher). The value of H2S in ppm to be used in the calculation must also be from stable flowing conditions. Note: H2S sampled in short production tests, is generally lower than the actual value under stabilised conditions. The following algorithm is used to calculate the pH2S: Step 1 pH2S is calculated at the separator (pH2Ssep): pH2Ssep = (Psep x H2Ssep)/106

Eq. 6.C

where: Psep

=

H2Ssep

=

Absolute mean pressure at which the separator works (from tests) in atm Mean H2S value in the separator gas (generally measured in ppm)

The mean molecular weight of the produced oil, PM : PM =

γ × 1000 GOR γ × 1000 + × (d × 29 ) GOR 23.6 − 23.6 PM giac

Eq. 6.D

where: PM

=

Ci Mi d

= = =

 n   mean molecular weight of the reservoir oil =  Ci × Mi  / 100   i =l  Mole % of the ith component of the reservoir oil Molecular weight of the ith component of the reservoir oil Density of the gas at separator conditions referred to air =1

∑

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The quantity of H2S in moles/litre dissolved in the separator oil is calculated: [H2S]oil = (pH2Ssep/H1 x (γ x 1000)/ PM )

Eq. 6.E

where: H1

=

PM

=

Henry constant of the produced oil at separator temperature (atm/Mole fraction). (See Procedure for calculating Henry constant) Mean molecular weight of the produced oil

γ

=

Specific weight g/l of the produced oil

The quantity of H2S in the gas in equilibrium is calculated (per litre of oil): 6

[H2S]gas = (GOR/23.6 x H2Ssep/10 )

Eq. 6.F

where: GOR 23.6

= =

3

3

Gas oil ratio Nm /m (from production tests) Conversion factor

The pH2S is calculated at reservoir conditions:

pH2S = (([H2S]oil + [H2S]gas)/K ) x H2

Eq. 6.G

where: K

=

(γ x 1000/ PM + GOR/23.6) total number of moles of the liquid phase in

H2

=

the reservoir Henry constant for the reservoir temperature and reservoir oil (see procedure for calculating Henry constant)

In general, H2S corrosion can occur at either the wellhead or bottom-hole without distinction. There is SSC potential if pH2S >0.0035 atm and STHP >18.63 atm. Procedure For Calculating Henry Constant The value of the Henry constant is a function of the temperature measured at the separator. The mapping method can be applied for temperatures at the separator of between 20°C and 200°C. Given the diagram in figure 6.a which represents the functions H(t) for the three types of oils: •

Heptane PM

=100

•

N-propyl benzene PM

= 120

•

Methylnaphthalene PM

=142

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Remarks On The H1 Calculation Having calculated the molecular weight of the produced oil PM using the formula in eq. 6.d, the reference curve is chosen (given by points) to calculate the Henry constant on the basis of the following value thresholds: •

If PM > 142, the H(t) curve of methylnaphthalene is used.

•

If PM > 120, the H(t) curve of propyl benzene is used.

•

If PM > 100, the H(t) curve of heptane is used.

•

If 100 < PM < 120, the mean value is calculated using the H(t) curve of propyl benzene and the H(t) curve of methylnaphthalene.

• •

If 120 < PM < 142 the mean value is calculated using the H(t) curve of heptane and the H(t) curve of propyl benzene. Given FTHT, wellhead flowing temperature, the H1 value is interpolated linearly on the chosen curve(s). For this purpose the temperature values immediately before and after the temperature studied are taken into consideration.

Comments On The H2 Calculation Having calculated the molecular weight of the reservoir oil PM res, using temperature measured at the separator, H2 is measured in a similar way as H1.

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Henry atm/Y[H2S]

130

120

110

100

90

methylnaphthalene PM = 142 80

N-propylbenzene PM = 120 heptane PM = 100

70

60

50

40

30

20 20

30

40

50

60

70

80

90

100 110 120 130 140 150 160 170 180 190 200

T C°

Figure 6.A - H(t) Reference Curves Oversaturated Oil Oil is considered oversaturated when the gas in the fluid separates because the pressure of the system is lower than the bubble point pressure. Two situations can arise: Case A FTHP < Pb FBHP > Pb Case B FTHP < Pb FBHP < Pb

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Calculation Of Partial Pressure In Case A: 1)

Calculation is of the partial pressure in the reservoir: In this case pH2S is calculated in the way described for undersaturated oil.

2)

Calculation is of the partial pressure at the wellhead, i.e. when FTHP
Basic Method pH2S = STHP x Y(H2S)/100 where: STHP = Y(H2S) = pH2S

=

Static tubing head pressure [atm] Mole fraction in separated gas at STHP pressure and wellhead temperature Partial H2S pressure [atm]

The SSC phenomenon is triggered off at the wellhead if pH2S >0.0035 atm and STHP >18.63 atm. Calculation Of Partial Pressure In Case B: Calculation of partial pressure in the reservoir: In the reservoir the gas is already separated, FBHP
The PVTs are reliable, Y(H2S) >0.2%, the partial pressure is calculated as: pH2S = Y(H2S) x FBHP 1 where: Y(H2S) =

•

Molar fraction in gas separated at FBHP and at reservoir temperature (from PVT)

The PVTs are not reliable, the material balance method can be used as in the case of undersaturated oil; these are the worst conditions. The error made can be high when Pb > FBHP.

Calculation Of Partial Pressure At Wellhead The calculation method is that used for case A (FTHP
1

2

If the percentage (ppm) of H2S in the gas under static conditions is not known, the corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead. 2 If the percentage (ppm) of H S in the separated gas under static conditions is not known, the 2 corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead.

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Corrosion Caused By CO2 And ClIn the presence of water, CO2 gives rise to a corrosion form which is different to those caused by the presence of H2S. It also occurs only if the partial pressure of CO2 exceeds a particular threshold. As in the case of SSC, the possibility that corrosions exist in water cut values combined with the type of well and deviation profile is evaluated. If the conditions described in section 6.3.1 exist, then the pCO2 is then calculated. Gas Or Condensate Gas Wells The partial pressure is calculated: pCO2 = SBHP x Y(CO2)/100 where: SBHP = Y(CO2) = pCO2 =

Static bottom-hole pressure [atm] Mole fraction of CO2 Partial pressure of CO2 [atm]

Corrosion occurs if pCO2 >0.2 atm. Oil Bearing Wells The problem exists where there is wetting water; i.e.: • •

Water cut >15% for vertical wells. Water cut >1% for horizontal or highly deviated wells (> 80 degrees).

Undersaturated Oil Wells The partial pressure of CO2 is calculated: pCO2 = Pb x Y(CO2)/100 where: Pb = Y(CO2) = pCO2

=

Bubble point pressure at reservoir temperature Mole fraction of CO2 in separated gas at bubble point pressure (from the PVTs) Partial pressure of CO2 [atm]

Corrosion occurs if pCO2 >0.2 atm. The pCO2 values calculated in this way are used to evaluate the corrosion at bottom hole and wellhead; i.e. pCO2 at wellhead is assumed as corresponding to reservoir conditions.

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Oversaturated Oil The oil is considered oversaturated when the gas separates in the fluid because the pressure of the system is lower than bubble point pressure. Two situations may arise: Case A FTHP Pb Case B FTHP Pb pCO2 is calculated in the same way as undersaturated oil wells earlier in this section. pCO2 = Pb x Y(CO2)/100 where: Pb = Y(CO2) = pCO2 =

Bubble point pressure at reservoir temperature Mole fraction in separated gas at bubble point pressure (from the PVTs) Partial pressure of CO2 [atm]

Corrosion occurs if pCO2 >0.2 atm. Calculation Of pCO2 At Wellhead: pCO2 = STHP x Y(CO2)/100 where: Y(CO2) = STHP =

Mole fraction in separated gas at STHP3 Static tubing head pressure [atm]

Corrosion occurs if pCO2 >0.2 atm.

3

If the percentage (ppm) of CO2 in the gas under static conditions is not known, the corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead

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Calculation Of Partial Pressure In Case B: Calculation of pCO2 at reservoir conditions: pCO2 = FBHP x Y(CO2)/100 where: Y(CO2)

=

Mole fraction in separated gas at pressure FBHP (from the PVTs)

Calculation Of pCO2 At Wellhead: The calculation method is the same as the one used in the wellhead conditions in case A: pCO2 = STHP x Y(CO2)/100 where: Y(CO2) =

Mole fraction in separated gas at STHP4

There is corrosion if pCO2 >0.2 atm. 6.3.3.

Corrosion Caused By H2S, CO2 And Cl-

It is possible to encounter H2S and CO2 besides Cl . In this case the problem is much more complex and the choice of suitable material is more delicate. The phenomenon is diagnosed by calculating the partial pressures of H2S and CO2 and comparing them with the respective thresholds.

4

If the percentage (ppm) of CO2 in the gas under flowing/static conditions is not known, the corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead.

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CORROSION CONTROL MEASURES Corrosion control measures may involve the use of one or more of the following: • • • • • • • • • • • • • • • • •

Cathodic protection Chemical inhibition Chemical control Oxygen scavengers Chemical sulphide scavengers pH adjustment Deposit control Coatings Non metallic materials or metallurgical Control Stress reduction Elimination of sharp bends Elimination of shock loads and vibration Improved handling procedures Corrosion allowances in design Improved welding procedures Organisation of repair operations.

Refer to table 6.a below. Measure

Means

Control of the environment

• • • • • • • • •

Surface treatment

• Plastic coating • Plating

pH Temperature Pressure Chloride concentration CO2 concentration 2 H S concentration 2 H O concentration Flow rate Inhibitors

Improvement of the corrosion resistivity of the Addition of steel structure

the

alloying

Table 6.A - Counter Measures to Prevent Corrosion

elements

micro

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CORROSION INHIBITORS An inhibitor is a substance which retards or slows down a chemical reaction. Thus, a corrosion inhibitor is a substance which, when added to an environment, decreases the rate of attack by the environmental on a metal. Corrosion inhibitors are commonly added in small amounts to acids, cooling waters, steam or other environments, either continuously or intermittently to prevent serious corrosion. There are many techniques used to apply corrosion inhibitors in oil and gas wells: • • • • • •

6.6.

Batch treatment (tubing displacement, standard batch, extended batch) Continuous treatment Squeeze treatment Atomised inhibitor squeeze - weighted liquids Capsules Sticks.

CORROSION RESISTANCE OF STAINLESS STEELS Stainless steel is usually used in applications for production tubing, however it is occasionally used for production casing or tubing below the packer depth. The main reason for the development of stainless steel is its resistance to corrosion. To be classed as a stainless steel, an iron alloy usually must contain at least 12% chromium in volume. The corrosion resistance of stainless steels is due to the ability of the chromium to passivate the surface of the alloy. Stainless steels may be divided into four distinct classes on the basis of their chemical content, metallurgical structure and mechanical properties these are:

6.6.1.

Martensitic Stainless Steels The martensitic stainless steels contain chromium as their principal alloying element. The most common types contain around 12% chromium, although some chromium content may be as high as 18%. The carbon content ranges from 0.08% to 1.10% and other elements such as nickel, columbium, molybdenum, selenium, silicon, and sulphur are added in small amounts for other properties in some grades. The most important characteristic that distinguishes these steels from other grades is their response to heat treatment. The martensitic stainless steels are hardened by the same heat treatment procedures used to harden carbon and alloy steels. The martensitic stainless steels are included in the ‘400’ series of stainless steels. The most commonly used of the martensitic stainless steels is AISI Type 410. The only grade of oilfield tubular used in this category is 13Cr. As their name indicates, the microstructure of these steels is martensitic. Stainless steels are strongly magnetic whatever the heat treatment condition.

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Ferritic Stainless Steels The second class of stainless steels, is the ferritic stainless steels, which are similar to the martensitic stainless steels in that they have chromium as the principal alloying element. The chromium contents of ferritic stainless steels is normally higher than that of the martensitic, stainless steel, and the carbon content is generally lower. The chromium content ranges between 13% to 27% but are not able to be hardened by heat treatment. They are used principally for their temperature properties. Ferritic stainless steels are also part of the ‘400’ series, the principal types being 405, 430, and 436. The microstructure of the ferritic stainless steels consists of ferrite, which are also strongly magnetic. Ferrite is simply body cantered cubic iron or an alloy based on this structure.

6.6.3.

Austenitic Stainless Steels The austenitic stainless steels have two principal alloying elements, chromium and nickel. Their micro-structure consists essentially of austenite which is face cantered cubic iron or an iron alloy based on this structure. They contain a minimum of 18% chromium and 8% nickel, with other elements added for particular reasons, and may range up to as high as 25% chromium and 20% nickel. Austenitic stainless steels generally have the highest corrosion resistance of any of the stainless steels, but their strength is lower than martensitic and ferritic stainless steels. They are not able to be hardened by heat treatment although they are hardenable to some extent by cold working and are generally non-magnetic. Austenitic stainless steels are grouped in the ‘300’ series, the most common being 304. Others commonly used are 303 free machining, 316 high Cr and Ni which may include Mo, and 347 stabilised for welding and corrosion resistance. These steels are widely used in the oilfield for fittings and control lines, but due to its low strength is not used for well tubulars.

6.6.4.

Precipitation Hardening Stainless Steels The most recent development in stainless steel is a general class known as ‘precipitation hardened stainless steels’, which contain various amounts of chromium and nickel. They combine the high strength of the martensitic stainless steels with the good corrosion resistance properties of the austenitic stainless steels. Most were developed as proprietary alloys, and there is a wide variety of compositions available. The distinguishing characteristic of the precipitation hardened stainless steel is that through specific heat treatments at relatively low temperatures, the steels can be hardened to varying strength levels. Most can be formed and machined before the final heat treatment and the finished product being hardened. Precipitation in alloys is analogous to precipitation as rain or snow. These are most commonly used for component parts in downhole and surface tools and not as oilfield tubulars. Refer to figure 6.b for the various compositions of stainless steels.

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Figure 6.B- Stainless Steel Compositions

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Duplex Stainless Steel In general, ferritic-austenitic (duplex) stainless steel consists of between 40-70% ferrite and has a typical composition of 22% Cr-5.5% Ni-3% Mo-0.14% N. The resulting steel has properties that are normally found in both phases: the ferrite promotes increased yield strength and resistance to chloride and hydrogen sulphide corrosion cracking; while the austenite phase improves workability and weldability. This material is used extensively for tubulars used in severe CO2 and H2S conditions. As a general note, there is a large gap between the 13Cr and Duplex Stainless Steels used as tubulars for their good anti-corrosion properties. This gap is attempted to be filled with ‘Super 13Cr’ tubing being developed.

6.7.

COMPANY DESIGN PROCEDURE

6.7.1.

CO2 Corrosion In producing wells, the presence of CO2 may lead to corrosion on those parts coming in contact with CO2 which normally means the production tubing and part of the production casing below the packer. Corrosion may be limited by: • •

6.7.2.

The selection of high alloy chromium steels, resistant to corrosion. Inhibitor injection, if using carbon steel casing. Generally, wells producing CO2 partial pressure higher than 20psi requires inhibition to limit corrosion.

H2S Corrosion In wells, where there is H2S, consideration should be given to limit casing and wellhead yield strength according to API 5CT and ‘NACE’ standard MR-01-75. Casing and tubing material will be selected according to the amount of H2S and other corrosive media present. Refer to figure 6.c and figure 6.d for partial pressure limits.

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Figure 6.C - Sour Gas Systems

Figure 6.D - Sour Multiphase Systems

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MATERIAL SELECTION The choice of material is based on the application of engineering diagrams supplied by manufacturers of tubing and, hence the use of the modified SMI has been adopted, refer to figure 6.e and figure 6.f. The choice of materials proposed is conservatively as recent develop materials such as 13%Cr and Super Duplex class have not been considered because experiments on these materials are not completed. In the partial pressures of H2S and CO2 are below the critical thresholds established in the previous section, all materials in class C-steel/L-A-steel can be used, otherwise the following combinations of conditions may exist: • • • •

Solely H2S in oil wells Solely H2S in gas or gas condensate wells Solely CO2 and Cl Both H2S and CO2.

The tables regarding the choice of materials are shown below. These give the rules used by Eni-Agip sectioned on the basis of the conditions as listed above and the use in the well. Materials are sub-divided into three categories, OCTG, DHE materials and wellhead materials.

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OCTG Specifications Refer to table 6.b below. OCTG Materials For Corrosion By H2S Only In Oil Wells Conditions o

0.0035< pH2S max < 0.1 0.0035< pH2S max < 0.1 0.0035< pH2S max < 0.1 pH2S max < 0.1

FBHT >80 C o o 60 C< FBHT >80 C o FBHT >80 C

Material

Alternately

J55, K55, N80, C95, P110 J55, K55, N80 L80 L80 Mod, C90-1, T95-1

L80-Mod, C90-1, T95-1 L80-Mod, C90-1, T95-1 L80-Mod, C90-1, T95-1

OCTG Materials For Corrosion By H2S Only In Gas Wells Conditions o

0.0035< pH2S max < 0.1 0.0035< pH2S max < 0.1

FBHT >80 C o FBHT <80 C

Material

Alternately

J55, K55, N80-2, C95 L80

L80-Mod, C90-1, T95-1 L80-Mod, C90-1, T95-1

OCTG Materials For Corrosion By CO2 And Cl* Conditions 0.2< pCO2S max <100 0.2< pCO2S max <100 0.2< pCO2S max <100

o

FBHT <150 C o o 150 C< FBHT <200 C o o 200 C< FBHT <250 C

Cl* <50,000

Material

Alternately

13% Cr 22% Cr 25% Cr-SA

25% Cr

OCTG Materials For Corrosion By CO2 , H2S And Cl* Conditions 0.2< pCO2S max <100e 0.0035< pH2S max < 0.005 0.2< pCO2S max <100e pH2S max <0.005 0.2< pCO2S max <100e 0.0035< pH2S max <0.005 0.2< pCO2S max <100e 0.0035< pH2S max <0.005 0.2< pCO2S max <100e 0.0035< pH2S max <0.005 0.2< pCO2S max <100e 0.005< pH2S max <0.1 pCO2S max <100e 0.005< pH2S max <0.1 0.2< pCO2S max <100e 0.005< pH2S max <0.1 0.2< pCO2S max <100e 0.1< pH2S max <1 0.2< pCO2S max <100e 0.1< pH2S max <1 0.2< pCO2S max <100e 0.1< pH2S max <1 0.2< pCO2S max <100e pH2S max >1

Material

Alternately

o

Cl* <50,000

13% Cr-80KSI Max

22% Cr 25% Cr

o

Cl* >50,000

FBHT <150 C

FBHT <200 C o

o

Cl* <50,000

o

o

Cl* <50,000

22% Cr CW 25% Cr CW 22% Cr 25% Cr 25% Cr

o

o

Cl* >50,000

25% Cr CW

o

Cl* <20,000

25% Cr

o

Cl* <50,000

25% Cr CW

Cl* <50,000

28% Cr

o

Cl* <50,000

22% Cr SA

o

Cl* <50,000

25% Cr SA

o

Cl* >50,000

28% Cr

22% Cr, 25% Cr Incoloy 825 28% Cr Incoloy 825 Incoloy 825

28% Cr

Incoloy 825

150 C< FBHT <200 C 200 C< FBHT <250 C 200 C< FBHT <250 C FBHT <250 C FBHT <250 C o

o

200 C< FBHT <250 C FBHT <200 C FBHT <250 C FBHT <200 C

Table 6.B - OCTG Materials for Sour Service

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DHE Specifications Refer to table 6.c below. Materials For DHE Corrosion By H2S Only In Oil Wells Conditions

Material o

pH2S max < 0.1 pH2S max < 0.1 pH2S max < 0.1 pH2S max > 0.1

FBHT >80 C o FBHT >80 C o FBHT <65 C o FBHT <65 C

Alternately

AISI-41XX-110KSI-MAX AISI-41XX-80KSI-MAX AISI-41XX-HRC-22-MAX AISI-41XX-HRC-22-MAX

Materials For DHE Corrosion By H2S Only In Gas Wells Conditions

Material o

pH2S max < 0.1 pH2S max < 0.1

FBHT >80 C

Alternately

AISI-41XX-80KSI-MAX AISI-41XX-HRC-22-MAX AISI-41XX-HRC-22-MAX

o

FBHT <80 C

Materials For DHE Corrosion By CO2 And Cl* Conditions pCO2S max <100 pCO2S max <100 pCO2S max <100

o

FBHT <100 C o o 100 C< FBHT <150 C o o 150 C< FBHT <250 C

Material

Alternately

28% Cr

Inconel 718 Incoloy 825

Cl* <50,000 Cl* <50,000

Materials For DHE Corrosion By CO2 , H2S And Cl* Conditions pCO2S max <100e pH2S max < 0.005 pCO2S max <100e pH2S max < 0.005 pCO2S max <100e pH2S max < 0.005 pCO2S max <100e pH2S max <0.005

Material o

FBHT <100 C

Cl* <50,000

9% Cr-1Moly

o

o

Cl* <50,000

13%-Cr-80KSIMAX

o

o

Cl* <50,000

o

o

Cl* <50,000

o

o

Cl* >50,000

22% Cr 25% Cr 25% Cr Inconel 718 Incoloy 825 22% Cr CW 25% Cr CW

o

o

Cl* >50,000

25% Cr CW

o

o

Cl* <50,000

25% Cr

o

o

Cl* >50,000

28% Cr

o

Cl* <50,000

22% Cr SA 25% Cr SA

o

Cl* <50,000

o

Cl* >50,000

25% Cr SA 28% Cr 28% Cr

100 C< FBHT <150 C 150 C< FBHT <250 C 200 C< FBHT <250 C

pCO2S max <100e pH2S max <0.005 pCO2S max <100e pH2S max < 0.005 pCO2S max <100e pH2S max <0.1 pCO2S max <100e pH2S max <0.1 pCO2S max <100e pH2S max <1

100 C< FBHT <150 C

pCO2S max <100e pH2S max <1 pCO2S max <100e pH2S max <1

FBHT <250 C

150 C< FBHT <250 C 200 C< FBHT <250 C 200 C< FBHT <250 C FBHT <200 C

FBHT <250 C

Table 6.C- DHE Material for Sour Service

Alter

Or

22% Cr 25% Cr Inconel 718 Incoloy 825

Inconel 718 Incoloy 825

Inconel 718 Incoloy 825 Inconel 718 Incoloy 825 Inconel 718 Incoloy 825 Inconel 718 Incoloy 825 22% Cr, Inconel 718 Incoloy 825 Inconel 718 Incoloy 825 Inconel 718 Incoloy 825

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Wellhead Specifications Refer to below. Wellhead Materials For Corrosion Caused By H2S

Conditions

Tubing Hanger

Tbg Head Adapter

Tubing Spool

Cross

Top Adapter

Casing Spool

Stud

Nut

pH2S-MAX > 0.035

AISI-4140 HRC-22MAX

AISI-4135 HRC-22MAX

AISI-4135 HRC-22MAX

AISI-4135 HRC-22MAX

AISI-4135 HRC-22MAX

AISI-4135 HRC-22MAX

ASTMA193-B7M

ASTMA194-2M

pH2S-MAX < 0.035

AISI-4140

AISI-4135

AISI-4135

AISI-4135

AISI-4135

AISI-4135

ASTMA193-B7M

ASTMA194-2H

Automatic-Master-Valve

Manual Master-Valve

Conditions

Body Bonnet Flanges

Gate & Seats

Steam

Body Bonnet Flanges

Gate & Seats

Steam

pH2S-MAX> 0.035

AISI-4135HRC-22-MAX

AISI-4140HRC-22-MAX

AISI-4140HRC-22-MAX

AISI-4135HRC-22-MAX

AISI-4140HRC-22-MAX

AISI-4140 HRC-22-MAX

pH2S-MAX < 0.035

AISI-4135

AISI-4140

AISI-4140

AISI-4135

AISI-4140

AISI-4140

Wellhead Materials For Corrosion Caused By CO2 and ClConditions

Tubing Hanger

Tbg Head Adapter

Tubing Spool

Cross

Top Adapter

Casing Spool

Stud

Nut

0.2
13%-Cr80ksi-Max F6NM


AISI-4135

13%-Cr80ksi-Max


Carbon-Steel AISI-41XX

ASTMA193-B7

ASTMA194-2H

Monel-K500 Inconel-718

AISI-4135-IC

AISI-4135

AISI-4135-IC

AISI-4135

ASTMA193-B7

ASTMA194-2H

-

FTHT < 150 Cl < 50000 pCO2-Max < 100 150
F6NM

Inconel-625

Cl- < 50000

AISI-4135IC Inconel 625 MonelK500

Inconel -625 Monel-K500

Automatic-Master-Valve

Manual Master-Valve

Conditions

Body Bonnet Flanges

Gate & Seats

Steam

Body Bonnet Flanges

Gate & Seats

Steam

0.2 < pCO2-Max < 100e

13%-Cr-80ksiMax

13%-Cr-80ksiMax

Monel-K500

13%-Cr80ksi-Max

13%-Cr80ksi-Max

Monel-K500

FTHT < 150e Cl < 50000

F6NM

17-4-PH

F6NM

pCO2-Max <100e

AISI-4135-IC

Inconel -718

AISI-4135-IC

150
Inconel-625

-

Cl < 50000

Inconel -718

Inconel-625

17-4-PH Inconel-718

Inconel-718

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0

Wellhead Materials For Corrosion Caused By H2S, CO2 and Cl Condition

Tubing Hanger

Tbg Head Adapter

Tubing Spool

Cross

Top Adapter

pCO2 -Max < 100

F6NM

13%-Cr 80ksi-Max

AISI-4135 HRC-22Max

13%-Cr80ksi-Max

13%-Cr 80ksi-Max

F6NM

F6NM

AISI-4135HRC-22Max

F6NM

F6NM

AISI-4135HRC-22MAX

F6NM

pH2S-Max <

F6NM

0.005

148 OF 295

-

Casing Spool

Stud

Nut

AISI-4135 ASTMHRC-22-Max A193-B7M

ASTMA194-2M

AISI-4135 ASTMHRC-22-Max A193-B7M

ASTMA194-2M

FTHT < 150 Cl < 50000

pCO2-Max < 100

F6NM

pH2S-Max < 0.2

MonelK500

FTHT < 150

F6NM

ASTMA194-2M

Cl < 50000

pCO2-Max < 100

F6NM

pH2S-Max < 0.2

MonelK500

FTHT < 150

F6NM

F6NM

AISI-4135HRC-22MAX

ASTMA193-B7M

AISI-4135 HRC-22MAX

MonelK500

MonelK500

Inconel718

Inconel718

-

Cl < 50000 pCO2-Max < 100 pH2S-Max <0.8

Inconel718

Inconel625

FTHT< 150 -

Cl < 50000

pCO2-Max < 100 pH2S-Max <0.8 -

Cl > Water 50000 pCO2-Max <100 pH2S-Max e > 0.8

AISI-4135IC

Inconel718

AISI-4135IC Inconel625

AISI-4135 HRC-22MAX

AISI-4135 HRC-22Max

AISI-4135- AISI-4135IC IC Inconel625

Inconel625

MonelK500

MonelK500

AISI-4135- AISI-4135- AISI-4135 IC IC HRC-22-Max Inconel625

Inconel625

Inconel718

Inconel718

ASTMA194-2M

ASTMA194-2M

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Automatic-Master-Valve Conditions

Body Bonnet Flanges

pCO2 -Max < 100 13%-Cr-80KSIMax pH S- Max < 2

0.005

149 OF 295

0

Manual Master-Valve

Gate & Seats

Steam

Body Bonnet Flanges

Gate & Seats

Steam

13%-Cr-80 KSIMax

17-4-PH F6NM

13%-Cr-80KSIMax

13%-Cr80KSI- Max

17-4-PH

13%-Cr80KSI- Max -

Monel-K500

F6NM

F6NM

F6NM

FTHT < 150 Cl < 50000

pCO2- Max < 100

F6NM

pH2S- Max < 0.2

13%-Cr-80 KSIMax

FTHT < 150

Stellite-6

Monel-K500

F6NM

Stellite--6

-

Cl < 50000 pCO2- Max < 100

AISI-4135-I.C.

F6NM

pH2S- Max < 0.8

Inconel-625

Inconel-718

Monel-K500

AISI-4135-I.C.

F6NM

Inconel-625

Inconel-718

AISI-4135-I.C.

Inconel-718

Monel-K500

FTHT< 150 -

Cl <50000 pCO2- Max < 100 AISI-4135- I.C. pH2S- Max < 0.8

Inconel-625

Inconel-718

Inconel-718

Inconel-625

-

Cl Water 50000 pCO2- Max < 100 pH2S- Max e > 0.8

Table 6.D- Wellhead Material for Sour Service

Inconel-718

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100 pCO2 (atm)

10

1

FBHT <= 150 C and Cl- <= 50000 ppm 13% Cr

FBHT<= 250 C and Cl- <= 20000 ppm 25% Cr-CW

150 > FBHT <= 200 C Cl- <= 50000 ppm 22% Cr

FBHT<=250 C and Cl- <= 50000 ppm 25% Cr-CW

200
10-1

(*)

200 50000 ppm 28 % Cr or INCOLOY- 825

0

FBHT <= 200 C Cl-<=50000 ppm 22 % Cr-SA or 25 % Cr-SA 28 % Cr INCOLOY- 825

(*)

FBHT < 200 C 28 % Cr or INCOLOY-825

FBHT <= 250 C Cl- <= 50000 ppm 25 % Cr-SA or 28 % Cr INCOLOY- 825 FBHT<= 250 C Cl- > 50000 ppm 28 % Cr INCOLOY- 825

C- STEEL J 55 N 80 P 110

10-3

200 < FBHT <= 250 Cl- > 50000 ppm 25 % Cr-CW

FBHT >80 C J55 K55 N80-1 C95 P110-1 (only oil) or L80 mod C90 T1

LOW ALLOY STEEL L 80 mod C 90 T1 C 95 T1

10-4

10-3

10-2

FBHT <= 200 C Cl- > 50000 ppm 22 % Cr- CW 25 % Cr -CW

200 < FBHT <= 250 C Cl- < 50000 ppm 25 % Cr-CW

65 < FBHT<= 80C J 55 K 55 N80-1 or L 80 mod C90 T1 T 95 T1

10-4

FBHT<= 150 C Cl- <= 50000 ppm 13 % Cr 80 Ksi max or 22 % Cr 25 % Cr

150 < FBHT <= 200 C Cl- < 50000 ppm 22 % Cr 25 % Cr

FBHT < = 65 C L 80 or L 80 mod;C 90 T1 T 95 T1

10-2

150 OF 295

10-1

1

10 100 pH2S (atm)

Figure 6.E - OCTG Material Selection Diagram

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100 pCO2 (atm)

10

1

FBHT <= 100 C Cl- <= 50000 ppm 9 Cr 1 Mo 100 < FBHT <= 150 C Cl- <= 50000 ppm 13 % Cr 80 ksi max 150 > FBHT<= 250 C 25% Cr-CW or 25% Cr INCONEL 718 INCOLOY 825

10-1

200 < FBHT<= 250 C Cl- <= 50000 ppm 25 % Cr or INCONEL 718 INCOLOY 825

(*) 200 < FBHT<=250 C Cl- > 50000 ppm 28 % Cr or INCONEL 718 INCOLOY 825

0

FBHT <= 200 C Cl-<=50000 ppm 22 % Cr-SA 25 % Cr-SA 28 % Cr INCOLOY 825 INCONEL 718

(*)

200 < FBHT <= 250 C Cl- <= 50000 ppm 25 % Cr-SA 28 % Cr INCOLOY 825 INCONEL 718

FBHT < 200 C 28 % Cr or INCOLOY 825 INCONEL 718

C-STEEL or AISI 41XX

100 < FBHT <= 200 C Cl- > 50000 ppm 22 % Cr-CW 25 % Cr-CW INCONEL 718 INCOLOY 825

65 < FBHT <=80 C C-STEEL 80 Ksi max AISI 41XX

200 > FBHT <= 250 C Cl- > 50000 ppm 25 % Cr-CW INCONEL 718 INCOLOY 825

AISI 41XX 22 HRC max

FBHT > 80 C C-STEEL 110 Ksi max AISI 41XX

10-3

10-4

10-4

10-3

10-2

150 < FBHT <= 200 C Cl- <= 50000 ppm 22 % Cr 25 % Cr INCONEL 718 INCOLOY 825

200 < FBHT <= 250 C Cl- > 50000 ppm 25 % Cr INCONEL 718 INCOLOY 825

FBHT<= 250 C Cl- > 50000 ppm 28 % Cr INCOLOY- 825 INCONEL 718

FBHT < = 65 C AISI 41XX 22 HRC max

10-2

151 OF 295

10-1

1

10 100 pH2S (atm)

Figure 6.F - DHE Material Selection Diagram

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6.9.

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ORDERING SPECIFICATIONS When ordering tubulars for sour service, the following specifications should be included, in addition to those given in the above table. 1) 2) 3) 4) 5)

6) 7)

Downgraded grade N80, P105 or P110 tubulars are not acceptable for orders for J55 or K55 casing. The couplings must have the same heat treatment as the pipe body. The pipe must be tested to the alternative test pressure (see API Bulletins 5A and 5AC). Cold die stamping is prohibited, all markings must be paint stencilled or hot die stamped. Three copies of the report providing the ladle analysis of each heat used in the manufacture of the goods shipped, together with all the check analyses performed, must be submitted. Three copies of a report showing the physical properties of the goods supplied and the results of hardness tests (Refer to step 3 above) must be submitted. Shell modified API thread compound must be used.

Note:

Recommendations for casing to be used for sour service must be specified according to the API 5CT for restricted yield strength casings.

The casing should also meet the following criteria: • •

The steel used in the manufacture of the casing should have been quenched and tempered. (This treatment is superior to tubulars heated/treated by other methods, e.g. normalising and tempering). All sour service casing should be inspected using non-destructive testing or impact tests only, as per API Specification 5CT.

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7.

TUBING DESIGN

7.1.

POLICIES

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0

All completion tubing strings will have tubing movement calculations conducted to ascertain the maximum load applied to the string and/or completion tubing movement to be catered for in the completion design. All tubing strings should be designed for stress, preferably using an appropriate up to date computer programme. Currently Eni-Agip Division and Affiliates recommended programme is the Enertech WS-Tube programme to the latest version. A safety factor (SF) of 1.25 applies to the ratio of the calculated stress in a string to the minimum yield strength of the selected tubing in carbon steels. A safety factor (SF) of 1.35 applies to the ratio of the calculated stress in a string to the minimum yield strength of the selected tubing of CRA materials. If the stress SF is less than these limits, the calculation should be run again substituting, either a heavier weight or, a higher grade of pipe. Under some special conditions, the SFs may be reduced, refer to the criteria in section 7.10.2. Tubing size shall be determined by the reservoir engineers using IPR curves and Nodal analysis (Refer to section 5.6). 7.2.

THEORY During completion tubing design process, it is necessary to calculate the variations in length for the stresses applied under load conditions. When these have been determined it will confirm the suitability of the selected tubing. Tubing movement occurs due to only two reasons: • •

Temperature changes Change in pressure induced forces.

Movement can only occur if the tubing is free to move. If the tubing is not free to move and is anchored to a packer then stress will be subjected to the tubing string and packer. This relationship is fully explained in section 7.10 Stress Calculations. Tubing movement upwards (contraction) is assumed to be negative and downwards (lengthening) is positive. To fully understand these effects, it is first necessary to understand the properties of steels used in the manufacture of tubing.

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7.2.1.

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Mechanical Properties of Steel Failure of a material or of a structural part may occur by fracture (e.g. the shattering of glass), yield, wear, corrosion, and other causes. These failures are failures of the material. Buckling may cause failure of the part without any fracture of the material. As load is applied, deformation takes place before any final fracture occurs. With all solid materials, some deformation may be sustained without permanent deformation, i.e., the material behaves elastically. Beyond the elastic limit, the elastic deformation is accompanied by varying amounts of plastic, or permanent, deformation. If a material sustains large amounts of plastic deformation before final fracture, it is classed as a ductile material, and if fracture occurs with little or no plastic deformation, the material is classed as brittle. Tests of materials may be conducted in many different ways, such as by torsion, compression and shear, but the tension test is the most common and is qualitatively characteristic of all the other types of tests. The action of a material under the gradually increasing extension in the tension test is usually represented by plotting apparent stress (the total load divided by the original cross-sectional area of the test piece) as ordinates against the apparent strain (elongation between two gauge points marked on the test piece divided by the original gauge length) as abscissae. A typical curve for steel is shown in figure 7.a. In this, the elastic deformation is approximately a straight line as called for by Hooke's Law, and the slope of this line, or the ratio of stress to strain within the elastic range, is the modulus of elasticity E, sometimes called Young's Modulus. This gives rise to Poisson’s Ratio, both are explained in figure 7.b.

Figure 7.A - Stress-Strain Curve for Tubing Steel

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Beyond the elastic limit, permanent or plastic strain occurs. If the stress is released in the region between the elastic limit and the yield strength; see figure 7.a, the material will contract along a line generally nearly straight and parallel to the original elastic line, leaving a permanent set.

Figure 7.B - Deformation Constants for Tubing Steel

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In steels, a curious phenomenon occurs after the elastic limit, known as yielding. This gives rise to a dip in the general curve followed by a period of deformation at approximately constant load. The maximum stress reached in this region is called the upper yield point and the lower part of the yielding region the lower yield point. In the harder and stronger steels, and under certain conditions of temperature, the yielding phenomenon is less prominent and is correspondingly harder to measure. In materials that do not exhibit a marked yield point, it is customary to measure a yield strength. This is arbitrarily defined as the stress at which the material has a specified permanent set (the value of 0.2% is widely accepted in the industry). For steels used in the manufacturing of tubular goods, API specifies the yield strength as the tensile strength required to produce a total elongation of 0.5% to 0.6% of the gauge length. Similar arbitrary rules are followed with regard to the elastic limit in commercial practice. Instead of determining the stress up to which there is no permanent set, as required by definition, it is customary to designate the end of the straight portion of the curve (by definition the proportional limit) as the elastic limit. Careful practice qualifies this by designating it the proportional elastic limit. As extension continues beyond yielding, the material becomes stronger causing a rise of the curve, but at the same time the cross-sectional area of the specimen becomes less as it is drawn out. This loss of area weakens the specimen so that the curve reaches a maximum and then falls off until final fracture occurs. The stress at the maximum point is called the tensile strength or the ultimate strength of the material and is its most often quoted property. The mechanical and chemical properties of casing, tubing and drill pipe are laid down in API specification of further specs. 5CT which is a combination of former specs. 5A, 5AC, 5AX and 5AQ - Casing and Tubing requirements. Depending on the type or grade, minimum requirements are laid down for the mechanical properties, and in the case of the yield point even maximum requirements (except for H-40). The denominations of the different grades are based on the minimum yield strength, e.g.: H-40 - min. yield strength 40,000 psi. J-55 - min. yield strength 55,000 psi. L-80 - min. yield strength 80,000 psi. Others are shown in figure 7.c. The lines indicating equivalent hardness of 22 and 23 Rc indicates the tolerances for use of the materials in H2S conditions according to NACE which is fully described in section 7.9.4.

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Figure 7.C - Strengths of Various Grades of Steel

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7.2.2.

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0

Temperature Temperature changes cause expansion and contraction in metals which is a significant factor in tubing strings. All metals have a particular expansion rate which is termed the ‘Coefficient of thermal expansion’. For a given volume, an object will expand or contract through temperature change by the Co-efficient of thermal expansion for the type of material. -6

The co-efficient of liner expansion for tubular steels is usually 6.9 x 10 in/in/F°. 7.2.3.

Tubing Movement/Stress Relationship Steel tubing, as seen in the previous section 7.2.2 will expand or contract due to changes in temperature or pressure induced forces. If the tubing is free to move then the calculations will determine the maximum expansion or contraction which needs to be catered for by the utilisation of a tubing movement compensation system such as a packer and seal unit, a PBR, ELTSR or a travel joint depending on which type of packer system is utilised. If the tubing is attached to a packer, then the tubing is unable to move as it can in the free movement scenario and, in this case, changes in tubing stress will be exerted. This may increase or decrease the stress already exerted to the tubing when it was installed, which is the ‘initial’ tubing condition. All subsequent changes in temperature or pressure induced forces are calculated form this initial condition. There are three methods in which tubing is connected to the packer: a)

Tubing is fully free to move either way.

b)

The tubing is positioned where it is fully free to move upwards but its downward movement is restricted and stress applied to the packer.

c)

The tubing is connected to the packer by being threaded to, or latched to, the packer

Further explanation of these three modes are explained below. a)

Free Movement

The tubing is free to move fully upwards or downwards using the packer bore with a seal assembly, a PBR, a TSR or travel joint (Refer to figure 7.d below). Calculations must be conducted to establish the full tubing movement in order that the length of tubing movement device can be determined. These devices are usually available in 10ft stroke lengths or multiples of 10ft, i.e. 10ft, 20ft and 30ft. The movement determined by calculation should be used to select a device which accommodates this movement with a margin of error, e.g. with a calculated movement of + 6ft and - 3ft = total 9ft, a 20ft device should be selected as a 10ft device would not provide enough contingency for error, unless the movement was subsequently restricted as described in the next section.

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b)

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Limited Downward Movement

In this case the tubing is fully free to move upwards but is restricted in its downward movement (Refer to figure 7.e). This restricted downward movement results in further stress applied to the bottom of the tubing and, correspondingly to the packer. This additional stress will be calculated during the tubing movement calculations and must not exceed the stress limit for the tubing, otherwise permanent deformation will occur. c)

Anchored Tubing

In this case the tubing is anchored to the packer by being threaded to it (as in the case when using retrievable packers) or by using an anchoring device such as an Anchor Latch, Ratchet Latch, etc. (Refer to figure 7.f). When the tubing is anchored to the packer and movement is eliminated, it will result in increased tensional and compressive forces, hence increased stress in the tubing. This may be acceptable when temperature and pressure changes are not excessive. Similarly, the calculations will determine that the tubing stress limit is not exceeded.

Figure 7.D - Free Moving

Figure 7.E - Limited Movement

Figure 7.F - Anchored Tubing

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7.3.

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WELL DATA. The well data and parameters required (or already determined) to produce an accurate tubing movement/stress analysis and, hence, selection of a tubing are: • • • • • • • •

7.3.1.

Casing design profile Casing programme contingency profile Tubing size from optimisation analysis Pressure gradient Temperature gradient Reservoir fluids specific gravities Completion fluid specific gravities Production/injection or stimulation forecast.

Casing Profile/Geometry The planned casing design and contingency plans are required as they affect the tubing movement calculations (Refer to 4.1.1). Each casing or liner weight and corresponding length of section must be known to enable calculation. Deviation tables are also required.

7.3.2.

Tubing Data The optimum tubing size, determined by nodal analysis conducted by the reservoir engineers, is required and is the basis of all the calculations. The tubing grade is selected in accordance to the criteria listed in section 6 to combat the effects of any corrosion from the well conditions. The tubing movement/stress calculations will then determine the tubing weight or any change in grade required to meet with the applied SF for stress. The well deviation is also important to determine the type of packer/tubing seal device and/or tubing movement device to ensure that, either, straight pull or torque can be applied to the tubing downhole at the packer depth overcoming any frictional drag. Once the tubing size, weight and grade is confirmed then the appropriate rated completion components can be specified in order that the purchasing department can prepare tender documents.

7.3.3.

Bottom-hole Pressure Accurate initial and prognosed future formation pressures both static and dynamic are fundamental to tubing movement/stress calculations. These pressures can be obtained from previous well exploration test data or appraisal well test reports.

7.3.4.

Temperatures (Static and Flowing) Accurate well temperature data are vital in tubing movement/stress analysis as the temperature effect is usually the effect which causes the greatest tubing movement. The average temperature of each section of tubing and casing must be known or determined to input into the calculations. Similar to the pressure data, temperature data may be found from previous well test results.

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7.3.5.

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Reservoir Fluids As described earlier, the constituents of the produced reservoir fluids will initially determine the material required for the tubing. This is subject to any corrosion inhibition methods which may be implemented. Particular importance should be paid to Hydrogen Sulphide, Carbon Dioxide and Chloride levels. In the presence of water and under certain temperature conditions, these corrosive agents can cause serious problems, therefore it is essential that a detailed corrosion study is completed to enable the choice of materials and/or inhibition procedures. If justified economically, the material chosen should combat the effects of corrosion, however if this choice is not economic and some corrosion inhibition process was suitable then this would be a fallback position. Future parameters must also be considered as water may rise and the GOR will change, therefore the materials should be chosen to last the planned life of the completion.

7.3.6.

Completion Fluid The completion fluid, usually a brine, is chosen for its compatibility with the formation and its fluids so as not to cause any formation damage. It should be selected to provide an overbalance at the top of the reservoir. It also must be selected for its stability over long time periods and not suffer from dehydration or deterioration. As the completion fluid (sometimes referred to as the packer fluid) will be left in the annulus, it should be suitably dosed with corrosion inhibitors and oxygen scavenger to prevent corrosion to the exposed tubulars and elastomers. The information required to make a considered selection may be obtained from the ADIS (Advanced Drilling Information System) database (which holds all the data regarding the drilling of the well), well tests carried out earlier and other sources which may be useful in the decision making process.

7.4.

PRESSURE INDUCED FORCES When a well is completed, either with a tubing seal unit in a packer bore or a tubing movement device, it will have completion fluid in both the tubing and the annulus, this is referred to as the initial condition. All subsequent conditions are calculated from this initial condition. These are three pressure induced effects which produce forces that moves the tubing. These effects are: a)

Piston effect.

b)

Buckling effect.

c)

Ballooning effect.

Each of these effects are addressed in this section.

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Piston Effect Tubing, when run in a well must first withstand the load of its own weight which may be a significant factor especially in deep wells. This tensile load is greatest in the joint immediately below the tubing hanger. The tubing is run into a completion fluid with equivalent fluid density inside and outside the tubing which results in a reduction of the load due to buoyancy. If there is an alteration from this initial condition causing a change in pressure forces across the packer seal unit then a piston effect is caused. This will alter the tensile load on the top and bottom of the tubing. The change in length due to these alterations is calculated from Hooks Law: Where E is the modulus of elasticity (sometimes referred to as a Young’s Modulus formula). The force (F) change is caused by the change in piston force from the initial conditions created by a change in pressure in the annulus or tubing at the packer. 7.7 and figure 7.h illustrate this piston force for two cases, tubing larger than the packer bore, and tubing smaller than the packer bore. The formula in each case is the same:

∆L1 = −

L F EAs

Eq. 7.A

Substituting for F, the equation becomes:

∆L1 = −

L EAs

[(Ap − A1) ∆P1 − (Ap − Ao ) ∆Po]

where:

L E As Ap Ai Ao ∆Pi ∆Po

= = = = = = = =

Length of the tubing string to the packer depth (ins) Young’s Modulus of Elasticity (psi) 2 Cross sectional area of tubing (ins ) 2 Area of the packer bore (ins ) 2 Area of the tubing ID (ins ) 2 Area of the tubing OD (ins ) Change in tubing pressure at the packer (psi) Change in annulus pressure at the packer (psi)

Eq. 7.B

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Ao

Ao

Ai

Ai

r

Ap

0

r

Po

Pi

Figure 7.G - Packer Bore Larger Than Tubing OD 7.4.2.

163 OF 295

Po

Ap

Pi

Figure 7.H - Packer Bore Smaller Than Tubing OD

Buckling Effect Helical buckling is initiated by compressive force acting on the bottom of the tubing and is the formation of helical spirals in the tubing string. The helix shown in figure 7.i has a variable pitch as the compressive force is progressively lowered by the weight of the pipe hanging below. The buckling effect is greater when pressure differential is applied across the pipe. Unless the tubing string is short or the compressive force is exceedingly high, some of the tubing will be buckled and the rest straight. The exact point between the buckled and straight sections is the ‘neutral point’ (Refer to figure 7.i). The neutral point can be calculated from the following:

n=

F w

where: W Wi Wo

= = =

Ws + Wi - Wo Ai x Weight of fluid inside the tubing Ao x Weight of fluid outside the tubing

Eq. 7.C

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Figure 7.I - Neutral Point When the neutral point is within the tubing length (and so the helix can fully develop), the length reduction due to helical buckling (Refer to figure 7.i) can be calculated by the following formula:

F2 r2 ∆L2 = − 8EI w where:

I=

π (D 4 − d 4 ) 64

Eq. 7.D

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∆L2

F Figure 7.J - Helical Buckling If the tubing is very short (as happens for example on selective type completions between two packer’s) all the string may be affected by buckling and there is no neutral point. In this case, the length reduction due to the buckling effect is dependant upon the entire length of the string and can be calculated by the following formula:

n>L

∆L2 = −

F 2 r 2  Lw  Lw  2 −   8 EIw  F  F 

Eq. 7.E

As seen, the formulae for both piston effect and helicoidal buckling above has so far used F, i.e. the change in the piston force acting on the bottom of the tubing. However, in order to complete the understanding of the effects which lead to variations in length due to buckling, we must also consider the effect caused by pressure differential across a pipe. If the internal pressure in a pipe is greater than the external pressure, the tube remains straight only if it has an axially symmetric cross-section with no deformation to change its shape. This configuration is unstable and any distortion can lead immediately to a stable equilibrium condition which is helicoidal buckling. Helicoidal buckling is caused by the effect of the pressure which acts on the lateral surface of the pipe wall as the convex surface of the bend in a greater force is larger than the concave surface (Refer to figure 7.k). The internal pressure will therefore exert a greater force on the convex side of the helix, than that exerted on the concave section of the same bend. The resulting force will, therefore, create the helicoidal buckling configuration. The same occurs when the stable external pressure is greater than the internal pressure also resulting in helical buckling.

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Moreover, the effect of the external pressure on the tubing lateral surfaces is equivalent to a tensile force applied at the tubing bottom of:

F f = Ai Pi I

Ff

II

Eq. 7.F

= − Ao Po

Eq. 7.G

R

Po

R

Po

Pi

Internal pressure

Pi

External pressure

Figure 7.K - Pressure Induced Helical Buckling Effect From this it can be concluded that the effect of the internal pressure on the tubing lateral surfaces is equivalent to a compressive force applied at the bottom of the tubing. I

II

Therefore the tubing will be buckled by the piston force and by the sum of Ff and Ff . The fictitious force Ff is obtained from the sum of the three elements:

Ff = Ff + Ff I

II

+ Fa

Eq. 7.H

by substitution: F f = A p (Pi − Po )

Eq. 7.I

If Ff is greater than zero it will cause helical buckling and hence, if it is less than zero there is no deformation. It is however important to relate that the only force actually applied at the bottom of the tubing is the piston force, while the fictitious force is used only to calculate the buckling effect.

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It should be remembered that, to calculate the variations in length, the variations of the forces compared to initial conditions must be calculated. Therefore, to sum up: • •

in the ∆L1 (Hooke’s law), the variation of the piston force Fa must be used; in the ∆L2 (buckling), the variation of the fictitious force Ff must be used when this is positive, otherwise, being a tensile force, it cannot buckle the string and ∆L2 = 0. The theory above was developed considering Pi = Po in the initial conditions, it thus follows that the Ff is equal to zero and that the variation of fictitious force ∆Ff is therefore equal to the final fictitious force. 7.4.3.

Ballooning Effect The third element which changes the length of a string, due to the changes to internal and external pressure, is caused by ballooning. This effect occurs when ∆P = Pi - Po is positive and tends to swell the tubing which, contracts axially or shortens (Refer to figure 7.m). On the other hand, when ∆P = Pi - Po is negative, the tubing is squeezed and, expands axially or elongates. This is termed reverse ballooning (Refer to figure 7.l). The normally used simplified formula to calculate the ballooning or reverse ballooning effect is:

∆L3 = −

2ν ∆Pim − R 2 ∆Pom L E R2 −1

Eq. 7.J

In this the average internal and external pressure variations are defined by the formulae:

    +  Pi ( final ) − Pi (initial )   Pi ( final ) − Pi (initial )    bottomhole tophole ∆Pim = 2 Eq. 7.K

    +  Po ( final ) − Po (initial )   Po ( final ) − Po (initial )    bottomhole tophole ∆Pom = 2 Eq. 7.L Again this is developed from Hooke’s law using Young’s Modulus of elasticity (already used in the piston and buckling effect) and Poisson’ ratio. Poisson’s ratio v as earlier expressed is:

V=

∆t / t ∆L / L

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Figure 7.L - Reverse Ballooning 7.4.4.

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Figure 7.M - Ballooning

Temperature Effect The final effect considered when calculating tubing length variations, is the temperature effect which usually induces the largest movement. During a well operation, e.g. stimulation, the temperature of the tubing may be much less than that in, either, the initial or flow rate conditions. During well stimulations, significant quantities of fluids are pumped through the tubing at ambient surface temperature which may change the temperature of the tubing by several degrees. The formula used to calculate the change of length due to temperature effect is:

∆L4 = α ∆TM L Eq. 7.M where the average temperature variation in the string can be calculated as follows:

∆TM =

(T

final

− Tinitial )tophole + (T final − Tinitial )bottomhole 2

. Eq. 7.N

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In the formula α represents the material’s coefficient of thermal expansion. For steel this value is: α = 6.9 x 10-6 in/in/°F. figure 7.n shows typical geothermal temperature gradients during both stimulation and production conditions. It can be seen that the temperature variations to which the tubing is subjected may cause considerable changes to its length.

0

100

200

300 T (°F)

PRODUCTION

2500

5000

GEOTHERMAL

INJECTION

7500 D (feet) Figure 7.N - Typical Geothermal Gradients 7.5.

EVALUATION OF TOTAL TUBING MOVEMENT The sum of the length changes obtained from the changes in pressure induced forces and temperature effects, gives the total shift of the bottom end of the string at the packer depth where it is free to move in the packer-bore. This sum is calculated:

∆Ltot = ∆L1 + ∆L2 + ∆L3 + ∆L4 Eq. 7.O With free moving packer/tubing seals systems, the calculations are made for the selection of an appropriate length of seal assembly, PBR or ELTSR with anchored packer/tubing systems, this same calculation can be made to select the length of tubing movement devices such as telescopic or expansion joints. However, if no movement is converted to stress in the tubing, the resultant is stress on the packer (Refer to section 7.6).

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ANCHORED TUBING In some completions the tubing is firmly fixed to the packer, preventing any movement of the string when well conditions vary (figure 7.o). In this situation the tubing-packer forces generated by the presence of the anchoring must be determined so as to be able to confirm if the tubing-packer anchoring system and the packer have sufficient strength to safely withstand all the forces exerted. Moreover, once this force is known, the load on the tubing can be calculated to check if the completion components have sufficient strength.

Figure 7.O - Tubing Anchored To Packer The tubing-packer force can be calculated by initially assuming that the tubing is free to move in the packer seal-bore and it is possible to calculate the final total length change of the tubing under pressure and temperature variations of all conditions. Subsequently, the force needed to re-anchor the tubing to the packer can be determined. To understand this concept better, consider figure 7.p where it is presumed that the tubing can move away from its anchored condition while maintaining the seal with the packer and that the tubing undergoes only ∆L4 contraction caused by the temperature effect. Since no force is applied at the end of the tubing which could cause buckling, all the movement is linear and to restore to the tubing’s real anchored position, it is sufficient to impose a ∆L4 elongation by applying a force FP which is obtained from Hooke’s law:

∆L = −

FL EAs

⇒

FP = − ∆L4

EAs L Eq. 7.P

However, in general the problem of identifying the tubing/packer reaction is not linear due to the helical buckling effect and so, it is possible to use a graphical approach.

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The first step is to plot the characteristic strength/length variation of the system. This curve, shown in figure 7.p is determined by the size of tubing, on the material, radial distance between the tubing OD and casing ID and on the fluids in the well. This can be plotted using the following formulae:

∆L = −

FL EAs

( for F < 0 )

∆L = −

FL F 2 r 2 − EAs 8 EIw

( for F > 0 ) Eq. 7.Q

The second step is to identify, on the curve, the tubing representative point in the well when it is subjected to the fictitious force, even when this is negative. On the curve given in figure 7.q this condition is identified by intersection point (Ff, ∆Lf). Indeed, if a force of Ff, was applied at the end of the tubing, the cause of the buckling would be eliminated and the neutral point would return to the bottom in the tubing. The origin of the axis moves to the point found in this way (Ff ,∆Lf) and the diagram obtained has a total length variation of ∆LP = -∆ltot, so to position the tubing in the packer after contracting the string must be elongated accordingly. As shown in figure 7.q the Fp force, transferred between the tubing and packer, is then identified.

∆L4

Fp

∆L

∆L4

Fp

F

Figure 7.P - Graphical Representation Of Movement

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∆Lp

Fp

∆L

Fp ∆Lp

∆Lf

F

Ff

Figure 7.Q - Graphical Representation of Force 7.6.1.

Tubing Permitting Limited Motion Another method which may be used in some types of completions is that the tubing is fully or partially limited in downhole movement. In this method, after the packer is set, some of the weight of the string is set down on the packer, putting the tubing into compression or slackened-off (Refer to figure 7.r).

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Figure 7.R - Limited Downward Movement The shortening of the string caused by this, ∆Pso, makes it possible to limit the length variations of the string, for example, during an injection operation, therefore, ∆Ltot, i.e. the total length variation calculated as the sum of the above described effects, is decreased by ∆Lso. The ∆Lso value is determined using the following formula:

Fso L Fso2 r 2 ∆Lso = − − E As 8 E I w Eq. 7.R where:

Fso

=

slack-off force released on the packer.

With this type of anchoring it is, therefore, possible to limit the movements of the tubing with respect to the packer and consequently the length of the packer seal-assembly. If an anchored type constraint is considered then the tubing-packer force with respect to the anchored tubing can be reduced, e.g. in an injection operation. In practice, applying slack-off is the same as moving the packer upwards by ∆Lso, compressing the string and thus causing part of the length variation which would occur in any case at a later stage due to the effects described above. The same considerations can be made if ∆Ltot < 0 during the operation while, on the other hand, any elongation of the string would be prevented, causing a force on the packer which would be equal to that of the slack-off amount.

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Packer Setting A particular problem arises in tubing tied to packer completions when using hydraulic set packers, as pressure is applied to the tubing to set the packer, it changes the length of the tubing during the setting process. This in turn places stress in the tubing after the packer is set and the pressure is bled off. This stress needs to be taken into account to determine the total stress applied to the tubing. Hydraulic packers are set by plugging the tubing below the packer either by dropping a setting ball onto a shear out ball seat, or by installing a plug with wireline. The formulae for determine this tubing length change are:

∆Fa L EAs 2ν ∆Pim ∆L3 = − L E R2 −1 ∆L1 = −

(Hooke’s law) (ballooning)

where:

∆Fa = − Ai ∆Pi and ∆Pim=∆Pi 7.7.

TUBING LOAD CONDITIONS The load conditions of the tubing string during the well’s life causes stresses through the pressure, temperature and mechanical loads for each condition imposed. It is therefore obvious why, when selecting the type of tubing for a completion, it is essential to identify exactly what operations will be carried out in future to determine the consequent loads and thus the associated load conditions. A manual or computer programme is then used to calculate and then ascertain whether the given tubing is able to withstand the maximum load with an acceptable safety level. The operations normally carried out on a well for which the string control is necessary are illustrated below. These should be seen only as an example of load conditions as each case must be addressed individually as planned operations may vary. It is important, in any case, to analyse the characteristics of each operation in order to be able to identify the heavier loads which may be imposed.

7.7.1.

Pressure Testing The very first load condition experienced during and after the installation of the completion string is pressure testing. This involves applying predetermined test pressures to both the tubing and annulus. These pressures may be applied more than once during the installation operation. During the time taken to install the tubing, the completion will have warmed up to ambient well conditions, therefore the only load applied is the pressure induced forces of piston effect buckling and ballooning. However, the designed test pressures should be equal to or greater than any other subsequent pressures applied to the completion so the magnitude is high. This may be of particular concern when using large bore tubing movement devices as the forces generated by the test pressure are greater than packer tubing seal arrangements.

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Acid Stimulation Acid jobs are carried out to remove formation damage caused during drilling by the invasion of fluids and cuttings or to stimulate the formation by improving permeability. This operation is carried out by pumping a predetermined quantity of acid down the tubing to the formation at set pressures and flow rates. From the point of view of the stresses exerted on the tubing string, the maximum pressure able to be applied at the well head must be considered in order to determine the rate of acid which can be applied, together with the temperature variations caused by the injection of colder fluid. It may be necessary in some cases, to reduce the loads on the tubing by preheating the acid in order to limit the thermal expansion and pressurising the annulus to reduce the tubing ballooning effect. Friction reducers may also be used to increase flow at the same wellhead pressure, and decreasing the bottom hole pressure thus reducing the load. It is important to monitor the pressure and temperature trends during the operation as the acid rate will probably increase due to the effect of the acid on the formation. This may lead to greater cooling down of the tubing with reduced pressures. figure 7.s shows the pressure and temperature trends required to be known so as to ensure stress control of the string, according to the classical Lubinsky theory. Other data are often needed for more complex calculations, using computer programmes, which, in Eni-Agip Division and Affiliates case are in-house software which allows reproduction of the correct temperature trend.

7.7.3.

Fracturing Fracturing involves the propagation of fractures in the formation for the improvement of productivity of hydrocarbons. These fractures reach from the well bore deep into reservoir and allows better drainage. To carry out fracturing, the formation must be pressurised until one (or more) fractures are created. This entails obtaining in advance the injection parameters from various injectivity tests with increasing flow rates. The calculated flow rate is applied during the operation and the pressure trend (which usually decreases when the fracture is created due to the reduction of load losses in the formation) is monitored. With regard to the stresses on the string similar to acid stimulations, it is important to assess the drop in temperature caused by the injection of colder fluid which, is carried out at high flow rates even though of short duration. The pressures which can be attained, especially during the early injection stage, are higher than that during acid jobs. At times during these early stages, in order to exceed the fracturing gradient, the maximum allowable pressure for some well head equipment may be reached. This equipment must therefore be protected using special isolating tools or protection sleeves. To check the string design is suitable, the pressure and temperature trends can be plotted as shown by the previous example of the acid stimulation (figure 7.s), selecting the end of the operation as the final conditions but with a well head pressure equal to the maximum estimated.

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If during the initial stages of the operation, a significant break-down is forecast (by a marked reduction of pressure when the fracture is opened up in the formation). The latter condition may be too conservative, therefore two conditions should be checked; the first with high pressures without temperature variations, and the second with marked temperature variations and lower pressures.

0

100

200

300 T (°F)

0

INITIAL CSG AND TBG - FINAL CSG

2500

FINAL TBG

5000

7500 D (feet)

0

5000

10000

0 FINAL CSG

15000 P (psi)

FINAL TBG

2500

5000 INITIAL TBG

INITIAL CSG

7500 D (feet)

Figure 7.S - Pressure and Temperature Trends During Fracturing

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Flowing In this case it is not an operation carried out on the well but the normal flowing load conditions to which the string is being subjected. It is therefore very important to establish, or at least approximate, the pressure and temperature profiles during the life of the well. Different production situations will occur which cause changing load conditions; e.g. temperature differences between the beginning and end of the productive life or the need to increase or decrease the flow rate for reasons external to the well. Compared to the initial condition, the string undergoes temperature increases which cause elongation in the string. The resulting compressive forces may lead to the buckling phenomena and even cause the tubing to exceed its elastic limit. As shown in the diagrams of figure 7.t and figure 7.u, which give the pressure and temperature bottom hole trends as a function of the depth at production start up and when the reservoir is depleted, external pressure may be greater than internal pressure, making it necessary to ensure a collapse control of some sections.

7.7.5.

Shut-In Once a well is in production, it is necessary to interrupt production for maintenance or in order to take some data measurements. This shut-in operation involves closing the well during which the well head pressure increases because the reservoir pressure rises to static condition, pressuring up the fluids in the tubing. This load condition is considered critical as, at the moment of shut-in, the temperature of the string does not vary greatly due to the thermal inertia of the well. The situation is now similar to that during production but with well head pressures which are greater and hence increase the stresses on the string. figure 7.u shows typical pressure and temperature trends after a shut-in.

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0

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100

0

200

300 T (°F)

0

2500

FINAL TBG

5000 INITIAL CSG E TBG - FINAL CSG

7500 D (feet)

0

5000

10000

0

15000 P (psi)

FINAL TBG

2500

INITIAL TBG

5000 INITIAL CSG - FINAL CSG

7500 D (feet) Figure 7.T - Pressure and Temperature Trends in Normal Production Conditions

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Figure 7.U - Pressure and Temperature Trends in Depleted Reservoir Production Conditions

0

100

200

0

300 T (°F)

2500

FINAL TBG

5000 INITIAL CSG E TBG - FINAL CSG

7500 D (feet)

0

5000

10000

0 FINAL TBG

2500

INITIAL TBG


7500 D (feet)

15000 P (psi)

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0

180 OF 295

100

0

200

300 T (°F)

0

2500

FINAL TBG

5000 INITIAL CSG AND TBG - CSG FINAL

7500 D (feet)

0

5000

10000

0

15000 P (psi)

FINAL TBG

2500

INITIAL TBG


7500 D (feet) Figure 7.V - Pressure and Temperature Trends After Shut-In

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Load Condition Summary The operations described above were chosen because they are the most common and show which aspects of an operation must be known in order to determine which loads will have to be considered to verify string design. As shown in the examples above, it is important to be able to plot the pressure and temperature trends of the casing and tubing on the two pressure/depth and temperature/ depth diagrams for the moment before the packer is set (initial conditions) and at the end of this operation (final condition) or, in any case, during the stage considered most critical as regards the loads applied. Using the above diagrams, and knowing the completion configuration, the relative loads on the sections of the string can be calculated, generally this is greatest in the section above the packer and below the well head. If the string is tapered or has one, or more, intermediate packers, it will be necessary during the control stage to know the pressure and temperature data of all the packers and of the tubing cross-section variations and is good practice to plot these data on diagrams.

7.8.

TUBING SELECTION The tubing string selection procedure and subsequent stress analysis is fundamental to the completion design process as it is during these two stages, that the optimum solution is found through a sequence of approximations. By using an iterative method, i.e. by choosing and verifying the various possibilities, the correct safety factor for all the calculated load conditions expected during the life of the well, can be obtained. The Eni-Agip Division and Affiliates approach to choosing the tubing string is similar to that followed when designing any other mechanical part. A draft design is considered based on the expected well conditions and then this design is checked to obtain the safety factor(s). Alterations are then made to the draft completion until the ideal safety factor, which may differ depending on the local environmental conditions and on some parameters discussed below, is reached. Since the economic factor plays a primary role of importance when selecting a completion, it is necessary to assess all the various possible solutions. A typical example is that of wells with the presence of corrosive agents where either strings and down hole equipment can be made in Corrosion Resistant Alloy (CRA) or carbon steel with inhibitors injected downhole can be used. In both cases the problem of completing the well is solved but it is necessary to verify both cost and whether it is better to use on CRA, avoiding future workovers or if it is more economical to use carbon steel with an inhibition system and scheduled workovers.

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Critical Factors The main factors driving the choice of the string are described below. Taking into consideration the well conditions, it is then possible to identify the optimum mechanical solutions. Materials The choice of material for the tubing string depends mainly on the well environment, in terms of all the mechanical stresses and corrosivity of the fluids. In general, the ideal material is determined by the results of corrosion studies carried out prior to the tubing design stage, especially when the severity of the conditions suggest the use of expensive CRA materials (Refer to section 6). With regard to corrosion studies, it is always necessary to determine, the exact quantities of H2S, CO2, chlorides and water from production tests and to enter these data into an expert system, or for a quicker choice, using the engineering diagrams supplied by manufacturers. However, this method does not provide a solution to using carbon steel in conjunction with an inhibition system. In this case, it is best to base the choice on an appropriate corrosion study which takes into account many other parameters, e.g. thickness of the corrosion product, economics, frequency of workovers, etc. Once the choice of materials has been identified, it will be necessary to take into consideration their mechanical properties to ensure that a suitable factor can be verified in the subsequent stress analysis stage. Indeed, to complete a well with the presence of corrosive agents (H2S and/or CO2) the use carbon steel with controlled hardness and/or martensitic steel, is often sufficient though these only reach a maximum grade of T95 (95 ksi yield) therefore do not always meet with stress requirements in high pressures and great depth. When CRA steels are used (which must be cold worked in order to obtain the required mechanical characteristics), the possibility of anisotropies must be checked into as they generally imply a lower compressive yield load than tensile yield load and corresponding reductions for their use at high temperatures. The presence of residual tension may induce stress corrosion and over-stressing problems which must also be taken into consideration.

7.8.2.

Tubing Size And Weight One of the main elements of the completion string design process, is the choice of the size, wall thickness and grade of tubing which is optimum to requirements, outlined below. The inside and outside diameter of the tubing, and if the string has more than one size of tubing as in a tapered string, the length of each section needs to be determined at this point. Given that the dimensions of the tubing and components of the string (safety valves, landing nipples, etc.) must fit inside the production casing and/or liner, it is essential to establish the size in order to find out if it impacts on the casing design. Note:

It is vital that any detrimental impact caused by the casing programme is discussed with the drilling engineers to solve any problems, whether this entails changes to either the casing programme or the completion design.

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The first indications of tubing size obtained is from tubing inflow performance analysis. These studies can generally be completed quickly using Eni-Agip Division and Affiliates software which directly provides the diameters of tubing for the expected flow rates and projected rates, which take into account the type of fluid, surface pressures, bottom hole pressures and other parameters. Calculation of the tubing inflow performance is very complicated and time consuming in most cases and is not covered in this manual. Once the projected size of the tubing is established for the required flow rate then in gas, or gas condensate wells, it is necessary to calculate the velocities in the string during production. This rate must be lower than the rate at which erosion occurs. These threshold velocities can be found in API RP 14E. The most important value to be decided on the selected tubing is its mechanical strength. As explained in the following section, the loads resulting from the various load conditions (acid jobs, production, etc.) applied to the selected string, the safety factor under these loads against the yield strength are calculated. Once this calculation has been made, it may be necessary to increase the weight or grade because the string is too weak. In some particular situations non-traditional solutions must be chosen as some parameters, such as cost, limit the choices. In the case of a very expensive super austenitic steel string for example, it may be more appropriate to choose more structurally efficient solutions which use a tapered string with different diameters thus reducing the amount of material needed and therefore the cost. Wells in which hydrocarbons containing corrosive agents are produced are sometimes completed using carbon steel and it is accepted that a certain amount of the material will be lost through corrosion during the life of the well. The strings of these wells, which generally will be equipped with a corrosion inhibitor injection system, should therefore have added thickness so as to have sufficient material to last until the scheduled workover. The two cases; i.e. the new string (maximum thickness, maximum weight) and the workover stage (minimum thickness, minimum weight) must both be taken into consideration when calculating the string’s stress resistance. It is prudent in such cases to reduce through tubing interventions which knock off the corrosion exposing fresh material and, hence, faster wall thickness reduction. When choosing the thickness of the tubing forming the string, it is useful to consider the thickness tolerance adopted by the manufacturer of the selected tubing. API standards for carbon steels define a 12.5% eccentricity tolerance which means one point on the tubing’s circumference probably has less thickness. This value for CRA tubing’s is often only 10%. which provides a better safety factor under similar conditions. Another reduction of thickness which must be taken into account on used tubing, may be due to repairs, by grinding, carried out to remove tong marks. The above factors can often lead to a variety of solutions, so it is necessary to evaluate each one in order to obtain the most suitable solution in terms of cost, mechanical strength and practical feasibility.

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Anchoring Systems As illustrated earlier, the operations carried out during the life of a well cause movement of the tubing string which can depend on the type of tubing/packer seal system used between the bottom of the tubing and the packer, will generate different loads in the string will be generated. From figure 7.w, which shows the three most common types of packer/tubing systems, it is clear from this that the least severe system is where the tubing seal assembly is free to move in the packer bore. This system does, however, have some disadvantages which are often unacceptable such as dynamic seals. In very deep wells, with high pressures and temperatures the movements of the lower end of the tubing may reach several feet in magnitude and hence very long seal units would need to be used in the packer which brings related assembly and protection problems during running in. Another important problem of free tubing, is the continuous movement of the seal elastomers which may become damaged due to wear or from the debris deposited in the annulus above the packer. The best solution, due to the use of static seals, is systems to screw the tubing to the packer using a threaded connection on retrievable packer systems or to a tubing anchor (which allows the packer to be released when necessary) on permanent packer systems. This type of anchoring provides the solution to seal life, but leads to greater stressing of the tubing string. In preference, the free moving system is the first choice and if the loads it creates do not allow for a suitable safety factor during well operations are other systems considered.

Free Movement

Limited Downward Movement

Attached

Figure 7.W - Tubing/Packer Systems The second preference is where downward tubing movement is restricted i.e. using a NoGo locator shoulder fitted above the seal assembly where it is positioned to prevent the elongation of the string while leaving it free to shorten. This will reduce movement of the packer seal assembly by eliminating downward movement and upward movement would only occur in certain limited lead conditions (stimulations or fracturing). This will extend seal life.

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TUBING CONNECTIONS The Eni-Agip Division and Affiliates policy for tubing connections is that ‘the use of premium connections is mandatory’. In conjunction Eni-Agip Division and Affiliates also recommended that a premium connection be used for production casings and production liners, especially when the annulus is to be used for gas lift or an underbalance fluid is used as a completion fluid.

7.9.1.

Policy • •

The use of premium connections for tubing is mandatory. The use of premium connections for production casing is advised but not mandatory.

The connections to be used shall be qualified according to the requirements as set in the Eni-Agip Division and Affiliates procedure ‘Connection Procedure Evaluation’. 7.9.2.

Class of Service According to the specification STAP M-1-M 5006 ‘Connection Procedure Evaluation’, there are two service classes, I and II, termed Application Levels (AL). Application Level I applies to the most severe service conditions. To date three tubing connections have been qualified for the most severe conditions ALI. They are : Coupled Connections AMS 28 ( manufacturer Dalmine) Vam ACE ( manufacturer Vallourec and Sumitomo) Integral Connections Eni-Agip Division and Affiliates A-DMS (Dual Metal Seal) Other connections like Hydril CS, PJD Dalmine and Antares MS have not yet been subjected to the complete qualification programme as per STAP M-1-M- 5006 or API 5C5. They have however been used successfully for years with good results. They may be used for all service condition where an Application Level II connection is required.

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Selection Criteria The following are the selection criteria for connections used in different types of wells and operating conditions. Work string or well testing string: Integral AL1 connection shall be used Horizontal wells with Build up ≥ 20°/100 feet: Integral AL1 connection should be used Wells with TVD ≥ 4500m: Integral AL1 connection shall be used Producing Oil And Gas Wells (TVD < 4500m) Criteria

Requirement

NACE

no

no

yes

yes

Close Proximity

yes

no

yes

no

Differential WP 0 - 4000 psi

AL II

AL II

AL I

AL II


AL I

AL II (*)

AL I

AL I

Differential WP over 8000 psi (*) For Gas Injection wells, AL I

AL I

AL I

AL I

AL I

Table 7.A - Connection Specification Storage/Injection Gas Wells (TVD < 4500m) Criteria

Requirement


AL I


AL II

Table 7.B - Connection Specification

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Water Injection Wells (TVD < 4500m) Criteria

Requirement


AL II


AL II

Table 7.C - Connection Specification A flow chart reaffirming the above is shown in figure 7.x. Note: Section 7.9.4 explains the NACE and Close Proximity definitions. Differential working pressure is the maximum differential pressure (internal and/or external) to which the production string is subjected during the life of the well.

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Figure 7.X - Connection Application Level Selection Flow Chart

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NACE And Proximity Definitions NACE Requirement This applies to the partial pressure of hydrogen sulphide (H2S) in the produced fluid as defined by NACE Standard MR 01-75. Close Proximity A proximity assessment should be prepared to consider the potential impact of an uncontrolled well flow condition on the life of personnel and the environment around the wellhead. The following list of criteria can be used for determining this potential risk. Other criteria for consideration should be included when necessary. 100ppm Radius of Exposure (ROE) of H2S is greater than 50ft. from the wellhead and includes any part of a public area except a public road. Public area shall mean a dwelling, place of business, church, school, hospital, school bus stop, government building, a public road, all or any portion of a park, city, town, village, or other similar area that one can expect to be populated. Public road shall mean any federal, state, county or municipal street or road owned or maintained for public access or use. 500ppm ROE of H2S is greater than 50ft. from the wellhead and includes any part of a public area including a public road. • • • • • • •

Well is located in any environmentally sensitive area such as parks, wildlife preserve, city limits, etc. Well is located within 150ft. of an open flame or fired equipment. Well is located within 50ft. of a public road (lease road excluded). Well is located in state waters. Well is located in or near inland navigable waters Well is located in or near surface domestic water supplies. Well is located within 350ft of any dwelling.

These conditions are recommended minimum considerations. It will be necessary to meet any other local regulatory requirements. Texas Railroad Commission Rules The following information is taken from Texas Railroad Commission Rule 36: For determining the location of the 100ppm radius of exposure: X = [(1.589) (mole fraction H2S) (Q)] 0.6258 For determining the location of the 500ppm radius of exposure: X = [(0.4546) (mole fraction H2S) (Q)] 0.6258

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where: X = Radius of exposure in feet Q=

Maximum volume determined to be available for escape in cubic feet per day.

H2S =

Mole fraction of hydrogen sulphide in the gaseous mixture which could escape.

The volume used as the escape rate in determining the radius of exposure shall be that specified below, as is applicable: For the new wells in developed areas, the escape rate shall be determined by using the current adjusted open-flow rate of offset wells, or the field average current adjusted openflow rate, whichever is the larger. The escape rate used in determining the radius of exposure shall be corrected to standard o conditions of 14.65psia and 60 F. When a well is in an area where insufficient data exists to calculate a radius of exposure, but where hydrogen sulphide may be expected, a 100ppm radius of exposure equal to 3,000ft shall be assumed. 7.9.5.

CRA Connections For steels with a high chrome content (>13%), there is a tendency to gall during make up. This requires special surface treatment in the connection’s pin and box. The anti-galling treatments (e.g. Bakertron or copper plating) is always applied to the couplings to ensure the utmost coating, hence protection.

7.9.6.

Connection Data Data on tubing connections are available from API specifications and tables in industry handbooks.

7.10.

TUBING STRESS CALCULATIONS The final stage of the completion string design is the calculation of stress in areas under the highest loads. After these calculations are made, it is possible to determine how close the stresses are to the material’s yield strength. At this point of the process all the possible elements needed for the design verification are available; i.e. information about the load conditions, the type of tubing and materials to be used to meet the requirements outlined in section 6.8. Using the calculation theory illustrated previously, it is possible to calculate the forces acting on the packer, Fp, and consequently, the fictitious and piston forces in the string sections. During the verification stage it may be seen that the loads on the string are unacceptably high. The string or load conditions or the tubing strength must therefore be altered until the calculation produces an appropriate safety factor (SF). Computer programmes are very useful in this phase as it is possible to make repeated calculations quickly with different parameters.

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7.10.1. Calculation Methods Taking, as an example, the type of completion shown in figure 7.y, the sections where the string design must be verified are indicated by x-x at the well head and y-y at the downhole just above the packer. For other types of completions, string design must be verified at all the appropriate sections where there are variations in diameter, have intermediate packers or other discontinuities. With reference to figure 7.y, the tables below summarise the forces acting on the sections of the string which will be used for the design verifications. The asterix distinguishes the forces calculated in a completion with the string anchored to the packer verses those calculated for a string free to move in the seal bore. Section Y-Y (Packer) Tubing-Packer Mode

Piston Forces

Fictitious Forces

Free tubing

Fa

Ff

Tubing permitting limited motion and anchored

Fa* = Fa + F p

F f* = F f + F p

Table 7.D - Forces at Y-Y

Section X-X (Well Head) Tubing-Packer Mode

Piston Forces

Fictitious Forces

Free tubing

Fa tp = Fa − w s L

F f tp = F f − wL

Tubing permitting limited motion and anchored

Fa*tp = Fa* − w s L

F f*tp = F f* − wL

Table 7.E - Forces at X-X As can be seen, the forces at the well head coincide with those at the packer depth if L = 0. Therefore, to calculate forces on intermediate sections between the well head and packer depth, it is sufficient to use an intermediate length ‘l’ ( L > l > 0 ) measured from the packer, instead of ‘L’ of the previous formulae.

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X

X

Y

Y

0

Figure 7.Y - Example Completion #1 The piston forces obtained in this way are used to calculate the axial stress which is given by the expression:

σa =

Fa As

The fictitious force is used to calculate the axial stress caused by the tubing bending when helically buckled, it is given by the expression:

σb =

Dr Ff 4I

therefore, σb is calculated only if the section of the string to be verified is buckled.

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Now all the factors needed to determine the equivalent stress σa, σb, Po and Pi are available, i.e. the stress which, by applying suitable criterion (for the materials used in the oil industry the most appropriate is Von Mises), allows comparison of the stresses due to the different effects in a particular section of the string against the material yield stress rating. In this case the equivalent force will be the greater of the two, calculated using the expression below, which gives the equivalent stresses in the outside and inside wall of the considered tubing section. 2   P − P   P − R Po σ o = 3 i 2 o  +  i 2 + σ a ± σ b   R −1   R −1  2

2

 Pi − R 2 Po  R 2 (Pi − Po ) σb  σ i = 3 σ + + ±  a 2 2  R −1 R  R −1   2

   

2

As stated above, if the section to be calculated is buckled, both calculations must be made to determine the higher of the two values while, if there is no buckling σb = 0 and the greater stress is that in the inside wall, the equivalent stress is σeq = σi The higher of the stress values determined above will make it possible to obtain the SF of the string for the load conditions and the section considered:

SF =

σ sn σ eq

The SF must be greater than the minimum dictated by policy and listed in section 7.1 which gives the SF values to be used by Eni-Agip Division and Affiliates. 7.10.2. Safety Factor A completion string’s safety factor is defined as the ratio between the yield stress and the maximum value of the stress obtained as described above. It, therefore, provides a quick reference parameter to evaluate the magnitude of the stresses present in the tubing compared to the maximum acceptable. To calculate the SF the yield limit values of the material are taken into consideration so that there is no permanent corkscrewing of the string which could jeopardise, even if only slightly, its functionality. The Eni-Agip Division and Affiliates policy is to apply different types of material due to their different mechanical behaviours and resistance to corrosion. Carbon and CRA Steels up to 13%Cr The acceptable SF for these types of materials is:

1.25

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In each individual case the string design and stress analysis engineer may evaluate whether the acceptable SF can be lowered to 1.15 for some particular operations and for specific well conditions. (e.g. low pressure oil wells, economic decision not to use the next grade of tubing etc.). Cold Worked (CW) CRA Steels The acceptable SF for these types of materials which include duplex, super-austenitic and Incoloy is:

1.35 Similarly, the engineer may evaluate whether, for some particular operations and for specific well conditions, the acceptable SF can be lowered to 1.20. The different SF’s between the carbon and CRA steels can be attributed to the different behaviour of these materials for stress values above the yield point. As stated previously, the SF is calculated using the yield point but also the collapse rating of the string. This is a dangerous situation which occurs at the breaking point. figure 7.z shows the stress/strain diagrams for the above two types of materials. As can be seen, apart from the yielding the cold worked materials reach breaking point soon after the yield point while the carbon steels maintain a greater plastic deformation margin before the breaking point. Furthermore, the cold worked materials retain residual stress so, from both the viewpoint of stress corrosion and mechanical strength, the SF should be slightly higher. It is, therefore, clear that a higher SF for Cold Worked materials is required in order to maintain the same safety factor relevant to the breaking points for the two types of materials.

Figure 7.Z - Stress/Strain Diagrams

COLD WORKED

CARBON STEEL

σ

σ

σr

σ σsn r

σsn

σr = breaking point σsn = yield point ε = elongation

ε

ε

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The SF discussed up to this point is valid, if referred to only as in the condition of triaxial stress which, therefore, takes into consideration all the stress components to determine the σeq, from which it is possible to make a comparison with the yield load. Any other SFs, referred to, in a state of monoaxial stresses, cannot be compared in any way to those described in this manual because they take into consideration only one mode of loading. For example, tension tubing, if applied individually, causes a state of monoaxial stress. However, it would be incorrect to use the SF for tension alone because during the life of the well it will be subjected to a combination of stresses. 7.10.3. External Pressure Limit During the productive life of a well, conditions may occur making it necessary to limit the external pressure on the string. One example is a well at the end of its productive life with less pressure in the tubing than in the annulus, due to the depletion in reservoir pressure. Another example is downhole pumps for artificial lifting and are operated by the power fluid pumped down the annulus, which require substantial differential operating pressures. Calculation of external pressure is carried out using the formulae supplied by API Bulletin 5C3 which identifies four types of collapse at external pressure in relation to the D/t ratio and the Yp yield stress of the material. In fact the causes of collapse can range from material yield as in the case of pipes with a low D/t ratio, to the section’s elastic limit which occurs in thin-walled pipes. In order to use the API Bul 5C3 formulae, once D/t and Yp are known, the type of formula is chosen then the maximum withstandable pressure calculated. If an axial force is applied to the pipe as well as external pressure, the Yp value for use for calculations is adjusted using a special formula. 7.10.4. Packer Load Limits If the Fp force value transmitted by the string to the packer is known, it is possible to calculate this value under various well conditions. By evaluating the magnitude of this force and considering other factors such as the possibility of future recovery, the most suitable type of packer in relation to the completion type, can be determined. By using diagrams supplied by the manufacturer, it is possible to check whether well conditions come within the limits set by the packer rating. A typical diagram for packer force limits is shown in figure 7.aa. If the force exerted by the tubing on the packer (Fp = set-down, if negative, Fp = tension, is positive) and the differential pressure above and below the packer (Po>Pi above, Po
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(tension)

400

300

FORCE

(Thousands)

200

100

Safety zone

(set-down)

0

-100

-200 -20

-10

0

10

20

(Thousands)

(above)

PRESSURE DIFF.

(below)

Figure 7.AA - Typical Packer Force Limit Diagram 7.10.5. Example Manual Calculation As an example of applying the method detailed above, we can consider the single completion in the well shown in figure 7.bb. During a cement squeeze operation, the analysis of the possible packer/tubing configurations available in this set-up is free tubing to packer and fully anchored. This allows calculation of the variations in length and thereafter the anchoring force in the packer. Data: 7

2

Tubing 2 /8in 6.5lb/ft :

Ai = 4.68in 2 Ao = 6.49in 2 As = 1.81in R = 1.178 ws = 0.542lb/in 4 I = 1.61in σsn = 80,000psi

Casing 7in 32lb/ft:

ID = 6.094in r = 1.61in

Packer bore:

Dpb = 3.25in 2 Ap = 8.3in

Length of string:

L = 10,000ft = 120,000in

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Initial Conditions Initially both the tubing and the annulus are filled with 30° API oil, while the temperature is 60°F at the well head and 200°F at the bottom hole. figure 7.cc shows the pressure and temperature variations against depth. It should be noted that 30° API corresponds to a 3 specific gravity of 0.0317lb/in and, therefore, to a pressure gradient of 0.38 psi/ft. Final Conditions Final conditions are cement displacement with a specific gravity of 15lb/gal, obtained by pressurising the tubing at 5,000psi and the casing at 1,000psi. This operation causes the string to cool to 160°F at the bottom hole and creates the pressure and temperature trend 3 shown in figure 7.cc (15lb/gal corresponds to a specific gravity of 0.0649lb/in and to a pressure gradient of 0.7795psi/ft).

X

X

Y

Y

Figure 7.BB - Example Completion #2

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P (psi)

O

O

0

T (°F)

60

GEOTERMICO

CSG e TBG

10000

10000

3800

D (feet)

200

D (feet)

FINAL CONDITIONS O

1000

P (psi)

5000

O

T (°F)

60

TBG SQUEEZE

CSG

10000

4800

10000

12795

160

D (feet)

D (feet)

Figure 7.CC - Initial and Final Condition (Example #2) Calculation Method a)

Calculation of variations in length

The variation in the piston force between initial and final conditions is expressed by:

∆Fa = ∆Pi (Ap − Ai ) − ∆Po (Ap − Ao )

= 8995 (8.3 − 4.68) − 1000 (8.3 − 6.49) = 30751.9 lb

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so the variation in length according to Hooke’s Law (piston force) is given by:

L1 = −

Fa L 30751.9 x 120000 =− E As 30000000 x 1.81

= − 67.96 in The fictitious force, which is initially zero because Pi = Po, is given by:

F f = A p (Pi − Po )

= 8.3 x (12795 − 4800 ) = 66358.5 lb

As this value is positive, then the string is buckled, so it is necessary to determine the position of the neutral point in order to calculate the ∆L2. The weight of string, w, fully immersed in fluids, is calculated in the following way:

w fi = Ai γ

fi

= 4.68 x 0.0649 = 0.3037 lb/in w fo = Ao γ

fo

= 6.49 x 0.0317 = 0.2057 lb/in w = ws + w fi − w fo = 0.542 + 0.3037 − 0.20567 = 0.640 lb/in The neutral point from the bottom hole is therefore:

n=

Ff

w 66358.5 = 0.640 = 103685.16 in

As this distance is less than the length of the string, not all the string is buckled. The variation in length ∆L2, is calculated using the first of the two formulae in section 7.4.2.

∆L 2 = −

F2 r 2 8Elw

−(1.61×66358.5 ) 8×30000000×1.6×10.64 = −46.16 2

=−

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As regards the variation in length due to ballooning, the average variations in pressure along the string can be calculated using the formulae in section 7.4.3:

∆Pim =

(5000 − 0) + (12795 − 3800 ) 2

= 6997.5 psi

∆Pom =

(1000 − 0 ) + (4800 − 3800) 2

= 1000 psi Therefore, the variation in length caused by ballooning is as follows:

∆L3 = −

2ν E

x

∆Pim − R2 x ∆Pom xL 2 R −1

2 x 0.3 6997.5 − (1.178) x 1000 x x 120000 30000000 (1.178)2 − 1 2

=−

= − 34.73 in. As regards the variation in length due to temperature, the formula in section 7.4.4, is used to calculate the average variation in temperature along the string:

∆TM =

(60 − 60 ) + (160 − 200) 2

= − 20 °F The variation in length is therefore:

∆L4 = α ∆TM L

= 6.9 x 10 − 6 x (− 20 ) x 120000 = − 16.56 in. The variation in total length of the tubing, if the tubing can freely move in the packer-bore, is therefore given by

∆Ltot = ∆L1 + ∆L2 + ∆L3 + ∆L4 1 = − 165.4 in.

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Tubing Permitting Limited Motion

The variation in length calculated above, may sometimes be unacceptable, as it would create seal assembly lengths which are not practicable for the planned type of completion. One method for containing these elongations is to use a tubing permitting limited motion, as it off-loads weight on the packer after it is set (slack-off) and compresses the string. The slack-off operation modifies the variations in length the string will undergo during the subsequent cement squeeze stage as shown below. During initial conditions, oil is the fluid inside the tubing and so:

w fi = Ai γ

fi

= 4.68 x 0.0317 = 0.1483 lbs/in w = w s + w fi − w fo = 0.542 + 0.1483 − 0.20575 = 0.48 lbs/in. Assuming that the slack-off force off loaded on the packer is 20,000lb, the neutral point is located as:

Fso w 20000 = 0.485 = 41266.4 in. n=

from the bottom of the string. As this value is less than the total length of the string, it makes it possible to use the formula in section 7.6 in order to obtain:

Fso L Fso2 r 2 ∆Lso = − − E As 8 E I w

(1.61 x 20000) 20000 x 120000 =− − 30000000 x 1.81 8 x 30000000 x 1.61 x 0.485 = − 49.73 in. 2

The variation in the length of the string during the cement squeeze job, when there is a tubing permitting limited motion is given by:

∆Lsotot = ∆Ltot − ∆L so = − 165.41 − (− 49.73) = − 115.68 in. As can be seen, this value is lower than that calculated for a free tubing.

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Anchored tubing

If we assume a condition obtained with a tubing which only permits limited motion, giving so ∆Ltot = -115.68 in. This value may still be unacceptable so it is necessary to use anchoring in both directions. In this case as slack-off after setting the packer is present it is necessary to determine the force required to position the end of the tubing in the packer (Fp), thus so setting the elongation ∆Lp =-∆Ltot =115.68 in . Figure 8.6 shows the diagram obtained using the formulae which supplies the force/elongation characteristic for tension and compression. When the data of the example are replaced, the formulae below are obtained (the diagram can be quickly plotted by entering any F values and calculating the corresponding ∆L):

∆L = −

F 452.5

[in]

for F<0

∆L = −

F F2 − 452.5 95403727

[in]

for F >0 .

If the diagram is plotted with the value of the fictitious force calculated previously (66358.5lbs), it is possible to identify the point where the origin of the axes has moved to. From this point, movement in the direction of elongation by a ∆Lp value is made in order to locate the point which is distant from the curve by a Fp value. As figure 7.cc shows, Fp = 37000lbs, so the string is subject to stress at its lower end which is equal to 37,000lbs and the packer is forced upwards by the same amount. d)

Tubing Stress Control

If we consider a tubing anchored to the packer during a cement squeeze operation, with a slack-off of 20,000lbs, the fictitious and piston forces, calculated according to section 7.6, are:

Fa* = Fa + F p

= Pi (A p − Ai ) − P0 (A p − Ao ) + F p = 629 in.

F f* = F f + F p = 29358 lb

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In the section above the packer (figure 7.bb), the forces at the well head are:

Fa*tp = Fa* − w s x L = 629 − 6.5 x 10000 = − 64371 in. F f* tp = F f* − w x L

allungamenti [in]

= 29358 − 0.64 x 120000 = − 47442 in.

allungamenti [in]

100

50

20 -40

60

80

100 compressione [lbx1000]

-20

-50

Fp -100

∆Lp

-150

Ff

-200

20

40 compressione [lbx1000]

accorciamenti [in]

trazione [lbx1000]

40

Figure 7.DD - Anchored Tubing (Example #2)

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Bottom Hole The piston force generates an axial stress equal to:

Fa* σa = As 629 = 1.81 = 347 psi the deformation due to buckling generates an axial stress equal to:

Dr * Ff 4I 2.875 x 1.61 x 29358 = 4 x 1.61 = 21095 psi

σb =

If we replace the σa e σb, values, along with Pi = 12795 psi e Po = 4800 psi, the values below are obtained using the formulae in section 7.10: σo = 51688psi σi = 60223psi , therefore, if we consider the highest value found as equivalent force, the result is σeq = σi, we can obtain the following bottom hole safety factor:

SF =

σ sn σ eq

80000 60223 = 1.33 =

Well Head * As Ff tp < 0 the string at the well head is not buckled, σb = 0 and the greatest amount of stress is generated on the inner wall of the tubing:

σa =

Fa*tp

As − 64371 = 1.81 = − 35564 psi

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If we replace the σa value obtained and as pi = 5,000psi and po = 1,000psi, the value below is obtained using the formula in section 7.10:

σi = 36117 psi therefore as σeq = σi, , the well head safety factor is:

SF =

σ sn σ eq

80000 36117 = 2.21 =

The safety factor for the cement squeeze operation results as the lowest of obtained values, therefore:

SF = 1.33 This value is acceptable because the lower limit for a carbon steel string is 1.25. 7.10.6. Example Computation As an example we have included two cases of string calculations, carried out using the Wellcat programme supplied by Enertech. The first example is the same as that dealt with by Lubinsky. The second is a case history, analysed during completion studies for the Villafortuna-Trecate field. Particular attention should be paid to data entry and presentation of results in order to obtain knowledge of how the programme handles these two cases. For a description of the programme’s general functions, please refer to the notes in Appendix D and the user’s manual available in the Company’s library. Examples done with the Vertubing programme, have been deliberately omitted as this programme is no longer used by Eni-Agip Division and Affiliates. Therefore only a brief description has been given in Appendix D. For further information please refer to the user’s manual.

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8.

SUB-SURFACE EQUIPMENT

8.1.

PACKERS

0

The types of packer systems and applications have already been described in section 5.3.1. This section defines the series of criteria for choosing packer characteristics to apply to single and selective completions. The packers considered are listed in table 8.a below. The proposed criteria for the choice only take into consideration general technical aspects and do not cover the individual characteristics of particular models or tools, while still reflecting the needs which lead to selection of the most commonly used models. Once the packer type and model have been defined, the next stage is establish its performance to meet with all the expected operating conditions (applied force and pressure differences). For this reason regarding permanent packers, reference is made to the operating ‘Envelopes’; i.e. operating diagrams for the packers supplied by the manufacturer of the particular packer and to the pressure ratings for retrievable packers.

Type Of Packer

Setting Method

Permanent

Mechanical

Permanent/ Retrievable Retrievable

Setting Tool

Sealbore Features

• Hydraulic setting tool

• Std/Large/Dual

• Electric line

• Std/Large/Dual

Hydraulic

N/A

Std/Dual

Mechanical

N/A

Std/Large/Dual

Hydraulic

N/A

Std/Dual

Hydraulic

N/A

Hydrostatic

N/A

Weight

N/A Table 8.A - Packer Types

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Selection Procedure Packer selection has three stages: 1) 2) 3)

Selection of type of packer Selection of setting mechanism Selection of main packer accessories including the tubing-packer connection

In stage 3, stress analysis is carried out to check the completion string (packer and tubing) under the stress to which they are exposed, refer to section 7.5 which describes the iterative process of tubing weight/grade/stress calculations. 8.1.2.

Selection Criteria Various representations can be used to describe the categories of criteria. This section illustrates the flow diagrams, identifying the standard procedures for each stage (Refer to figure 8.a.). The selection process includes the following categories of data: General Well Data This includes data which effects the configuration of the well to be completed, the most important being: • • • • •

Location (on-shore/ off-shore platforms, off-shore under water) Pressures and temperatures Type of well (production, injection) Type of fluid produced (oil, gas) Deviation (max. deviation angle).

Completion Data This includes the following parameters such as: • • •

Type and density of the completion fluid Perforation of the casing using tubing-conveyed or wireline techniques Use of a production liner.

These data also include type of packer chosen and setting, setting depth, etc. Operational Data The following operational data are required: • •

Stimulations (planned, unplanned) Type of de-compression operations, in particular: a) removal of the tubing by itself b)

• •

removal of the tubing and packer simultaneously

Planned frequency of de-compression operations Potential damage to the formation caused by the workover fluid.

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Figure 8.A - Selection Process Diagram

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Well Classification An important parameter for defining the characteristics of a packer is the ‘degree of difficulty of the well to be completed’. To this end four classes of well have been identified which are used to analyse the various problems involved in the selection of the packer: 1)

High corrosive wells •

2)

Highly critical wells: • • • • • •

3)

Deep depths > 4500m. High temperatures, SBHT > 130°C. High pressures, SBHP > 700 atm. Subsea well-head well. Platform well having the risk of failure due to the potential collision from a vessel with the structure. Gas injection well with pressures, ITHP above 3,000psi.

Critical Well • •

4)

The fluids have high corrosive problems.

Temperatures between 100 and 130°C Depths between 3,000 and 4,500m.

Non-critical well • •

Depth of less than 3,000m. Temperatures below 100 °C.

The depths indicated are true vertical depths. 8.1.4.

Packer Selection For Single String Completion Type Of Packer Procedure The choice is mainly linked to the type of well: 1) 2) 3)

In the case of a highly critical well, select a permanent packer. If the well has high corrosive, select a permanent/retrievable or permanent packer, with priority be given to the former. If the well is critical or non-critical, (Refer to figure 8.b).

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Figure 8.B - Type of Packer for Critical and Non-Critical Wells Explanation of figure 8.b: (A) High frequency of tubing pullout. (B) High frequency of tubing-packer pullout. (C) Use of TCP drilling techniques. (D) Measured well depth ≥ 3000 m. (E) The workover fluid damages the formation. (F) The packer fluid is a high density mud (> 1.6 kg/l) with probable solid deposits on the packer. (G) Gas injection well with injection pressure > 3,000psi.

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At points A and B, high frequency of extraction corresponds to a completion life of less than five years. The rectangle ‘Choose’ indicates the choice between the two alternatives, the priority is indicated by a number (‘1’ corresponds to a higher priority than ‘2’). For example, in the choice is made on the basis of point (D) then there are no particular constraints (no workovers, or requests due to the completion fluid characteristics). The safety factor of using a retrievable packer or not depends on the criticality of the well and, in particular, on its depth. Packer Setting Method Permanent and Permanent/Retrievable Packers The selection is dependent mainly on the well characteristics: 1) 2) 3)

If the well is corrosive or very critical, choose hydraulic setting. If the well is critical or not critical, (Refer to figure 8.c). Reference (A) is only true if one of the following conditions are relevant: • • • •

SBHT > 150 °C (= 270 °F). Is a deviated well, with a maximum deviation angle > 50°. The completion fluid = mud with density > 1.6 kg/l. Gas a production liner with inclination > 30°.

Figure 8.C - Packer Setting Method for Critical and Non-Critical Wells For a mechanical type permanent packer, the setting is defined by the conditions detailed in (A). The same procedure will also be used later for packers of the type used in a selective type completion.

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Retrievable Packer Setting Method The method of setting used for retrievable packers is made, following the diagram in figure 8.d:

Figure 8.D- Retrievable Packer Setting Method 1)

Check (A) is only true if one of the following conditions are relevant: • • • •

2)

Check (B): •

3)

There is high frequency of tubing pullout (life of the completion < 5 years).

Check (E): •

5)

Using TCP shooting techniques.

Check (C): •

4)

The well is deviated with a maximum deviation angle of > 20°. The bottom-hole temperature (SBHT) is > 60 °C. The vertical depth of the packer setting is > 2,000m (this is true to definitive and not test completions). Stimulations are planned.

Completion fluid and damage to the formation

Check (F): •

The packer fluid is a high density mud (> 1.6 kg/l) with the probability that it leaves solid deposits on the packer.

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The decision of whether to use a hydraulic, or hydrostatic, set is left to the engineer. The main consideration is the required setting pressure (lower for hydrostatic packers) which influences the wellhead pressure rating. The conditions at the moment of packer setting decides whether to use a retrievable packer. If these are outwith the capacity of the retrievable packer, a permanent/retrievable packer will be utilised and consequently, the corresponding setting procedure will have to be adopted (see permanent packers above). Permanent And Permanent/Retrievable Packers Setting Method There are principally two aspects to analyse: • •

The choice of the tubing-packer connection. To integrate this choice with the stress analysis procedures.

If during the application of the stress analyses of the string gives negative results, a configuration which fulfils the stress analysis requirements must be considered for the packer-tubing connection5. The shear ring value is generally set by increasing the maximum force applied to the packer by 25%. The maximum force is determined using stress analysis (to take into account the tolerance of the nominal shear value ± 5 to 10%). The shear value is checked for the stress conditions at the wellhead section during the packer release stage. Tubing-packer connections seal assembly elements will be of the moulded seal type when subjected to alternating pressure cycles, e.g. gas injection wells where the IBHP is greater than the packer fluid pressure and SBHP is lower than the packer fluid pressure. Highly Critical Well: Anchored Completion For a highly critical well, the approach is the same as that for an anchored tubing-packer. defines the type of anchoring on the basis of the conditions for (A), in particular the choice is made between a shear release or anchor seal assembly. The type of anchor to be used can be defined during this first stage for an anchored completion (without shear release): •

If the packer is set mechanically, the anchor will be a ratchet type or, alternatively, fixed.

If the stress analysis results are negative: • •

If a shear release is needed, an anchor seal assembly is used. If anchor is needed, a dynamic seal is used (Refer to figure 8.d).

5 If the failure of the stress analysis is due to the tension caused by the tubing-packer connection. At present the stress analysis procedure is developed using the “Veritas “ software package .Veritas is the UNIX version of the VERTBG package.

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Figure 8.E - Anchored Completion Option Check (A): Deviated well: •

if it is an injection well it cannot be critical (see section 8.1.3).

For an anchor with shear release: •

If the stress analysis upon releasing is negative, an anchor will be used and the check will be carried out again.

Highly Critical Well: Dynamic Seal This stage considers an anchored completion which fails the stress analysis calculation because of problems associated with the tubing-packer connection. In this case a dynamic seal is used (Refer to figure 8.f).

Figure 8.F - Dynamic Seal Check (A)

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The packer fluid is a high density mud (> 1.6 kg/l) which may leave solid deposits on the packer.

Check (B): •

The packer is one trip installation, i.e. run on the tubing. This is only possible with hydraulically packers.

The procedure illustrated in figure 8.f gives a general description of the criteria behind the choice of dynamic seal to be adopted. Reference will be made to this later and also for cases which are different to those described in highly critical wells above. Here, following any failure of the stress analysis, no other rules are apply as, in general, when using dynamic seals, the stress analysis results are corrected using factors other than the seal element. Critical, Non-Critical Well The easiest solution in these cases is to choose a Standard Seal Locator. This is the case with the following conditions: • • •

No stimulations are planned. The well is not an injection well. The packer is not set hydraulically.

If these conditions do not apply, the procedure illustrated in figure 8.g is followed.

Figure 8.G - Critical and Non-Critical Wells, Seal Element

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Check (A): •

the packer fluid is a high density mud (> 1.6 kg/l) which may leave solid deposits on the packer.

•

deviated well with max. deviation angle > 20.

•

expected life of the completion < 5 years.

•

the packer is set mechanically.

(B):

(C):

(D):

Again in figure 8.g, the outlet conditions included in the rectangle indicate, besides the choice of tubing-packer connection, the need to use the packing setting procedure specified. In the case of a deviated well, anchored completion is not recommended. It is better to use a completion with a shear element which is more easily releasable, or a dynamic seal whenever feasible. No additional adaptation of the seal element is foreseen as a consequence of any stress analysis. Retrievable Packer Tubing-Packer Connections The choice of the tubing-packer connection for retrievable packers (hydraulic and set down weight) is made on the basis of that in figure 8.h. Particular conditions raise questions over which type of retrievable packer to use. In these cases, a permanent/retrievable packer is the priority or a permanent should be used and consequently the associated setting procedure and seal assembly selected.

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Figure 8.H - Tubing-Packer Connections for Retrievable Packers 8.1.5.

Single Selective Completion Packers The criteria illustrated here are valid for selective completions with 2 or 3 producing zones. The solutions given are for a case with only 2 zones and if a third zone is to be taken into consideration it is assumed that the selection made for the upper zone of the two zone scenario applies. Packer Selection The first case classifies the well on the basis of depth characteristics (≥ 4,000m) but more on the basis of its complexity.

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Figure 8.I - Single Selective Packer For Complex Wells if several different configurations are available, as for example in figure 8.i, the engineer has a certain degree of freedom of choice but is, however, governed by the order of priority specified along with the choices. If the conditions as of figure 8.i, are not applicable, these cases are classified by well depth:

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Figure 8.J - Selective Single Well with Depths Between 3,000 and 4,000m

Figure 8.K - Selective Single Well with Depths Between 1,500 and 3,000m

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Figure 8.L - Selective Single Well with Depths Less Than 1,500m In the case of depths less than 1,500m in a well not considered complex, it is strongly recommend that a retrievable type packer be used. Application of the criteria illustrated in figure 8.i through figure 8.l is common with the only exception, in the case of multiple choices, being that the order of priority for the lower zone can be changed by applying the following rules: • •

If workovers are planned with removal of the tubing and packer, and a retrievable packer is one in the list of possible choices, then it should be selected. If the completion fluid is a mud with deposition problems, and a permanent or permanent/retrievable packer are in the list of possible choices, then the permanent/retrievable should be selected over of the retrievable.

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Packer Setting Method The type of setting method proposed depends on the following factors: • •

Type of packer Setting distance between the packers.

The setting criteria of a mechanical permanent packer (on a workstring, or wireline) are those already defined for the single completion described in section 8.1.4. Permanent Stacked Packers: Refer to figure 8.i with all permanent packers, if the setting distance between the packers is > 500m (check with the packer manufacturer), choose hydraulic setting for all the packers or else mechanical setting. Lower Permanent Packer With Upper Retrievable: Refer to figure 8.j, figure 8.k and figure 8.l, in these cases the reference packer is permanent and the other packers are the retrievable or permanent/retrievable type. With these type of packers, if the completion fluid is a brine, hydraulic type setting should be used or else the packers can be set mechanically. Mechanical setting is preferred for the reference packer and the setting should be by electric line when the distance between the packers is < 500 m. If the reference packer is set by a workstring, a depth control procedure is necessary to verify the depth of the packer setting to ensure positioning of the blast joint across the upper zone which is open to production. All packers are Retrievable Refer to figure 8.k and figure 8.l where all packers are retrievable, hydraulic setting should be used for this type of packer. It is essential to check with manufacturers that the distance between the packers is sufficient for the packers to be set. Tubing-Packer Connection Selection The criteria continues by classifying the packers by type and setting with the zones treated separately. In some cases, three zones are assumed (upper, intermediate, lower). In cases where there is no specific mention of an Intermediate zone, it is treated with the same criteria used for the upper zone. Generally, the results of the stress analysis specifically identifies the packers with releasing problems. Due to this, the zones are be treated separately; i.e. modifications are be made only to those packers which have the problems. It is recommended in any case to re-check the completion after having made the modifications.

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Upper packer The rules described for the single completion are applied to the upper packer (Refer to 8.1.4). Lower or Intermediate Packer There are three possible ways of treating the lower zones: 1)

2)

3)

All the packers are of the permanent or permanent/retrievable types with hydraulic setting. Initially an anchor with shear release should be selected. In the case of failure of the stress analysis on this packer, a dynamic seal will be used (anchor with PBR or telescopic joint). The lower zone packer is a permanent with mechanical setting. A dynamic seal should be used; in particular, a standard length locator. In the case of failure of the stress analysis, a longer locator with seal bore extension should be used. For the intermediate zone in the three zone case, an anchor or retrievable type packer will be used, for the intermediate packer. The lower zone packer is a retrievable. In the case of failure in the stress analysis a dynamic seal with telescopic joint will be used.

For the intermediate zone in the case of three zones, a telescopic joint should be used when there is failure in the stress analysis.

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SUB-SURFACE SAFETY VALVES This section provides the Eni-Agip Division and Affiliates policy and guidelines for the application and selection of Sub-Surface Safety Valves (SSSV). The policy defined shall be applied to all Eni-Agip Division and Affiliates completion designs world-wide. Any variation to this policy and selection procedures herein, shall only be sanctioned by the Eni-Agip Division and Affiliates Head Office.

8.2.1.

Policy All Eni-Agip Division and Affiliates completions shall incorporate a SSSV in the completion string to provide safety in the event of an uncontrolled well flow. Surface controlled sub-surface safety valves (SCSSV’s) shall be used accordingly to the criteria listed below in section 8.2.4.

8.2.2.

Applications The applications for SSSV’s are given in section 8.2.5. The choice of SSSV for a particular development will depend on: • • • •

Well location Fluid properties Required flow area Well intervention capabilities.

This will determine whether the selected SSSV is Wireline Retrievable (WRSV) or Tubing Retrievable (TRSV). 8.2.3.

Wireline Retrievable Safety Valves Wireline retrievable valves may be, either, sub-surface controlled sub-surface safety valves (SSCSSV) otherwise known as direct acting valves or surface controlled sub-surface safety valves (SCSSV). SSCSSV’s are either pressure differential or ambient pressure operated valves. Both types are generally referred to as ‘storm chokes’. The use of these valves should be avoided as they are set up to operate on predetermined conditions representing a major leak at surface, e.g. a flowline rupture, but under some circumstances, when there is a leak of insufficient rate, the valve may fail to close. In conjunction, flow erosion of the valve internals may alter the closure settings. A derivative of the storm choke is the injection valve which is held open by water or gas injection and closes when injection ceases.

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Surface Controlled Sub-Surface Safety Valves These are designed for tubing retrievable, wireline retrievable or annulus safety valve systems. They are controlled normally by surface applied hydraulic pressure through a control line clamped to the outside of the tubing string. Hydraulic pressure opens and then retains the valve open. Removal of the pressure allows the valves to close. These valve systems are fail safe and are preferred to SSCSSV’s. The guidelines given in section 8.2.5 indicate in which applications WRSV’s and TRSV’s should be used. The following table 8.b specifies when SCSSV’s shall be used.

Well Type

Criteria

Oil Producer

• All new offshore development. • All wells onshore which can sustain natural flow. • All old wells in above categories which are to be recompleted. • All isolated wells.

Gas producer

• All new offshore development. • All old wells being recompleted.

Gas storage

• All wells.

Gas injection

• All wells.

Water injection

• All wells. • All wells on gas lift, tubing and annulus. • Electrical submersible pump, tubing and only annulus if used for gas venting.

Artificial lift

H2S in produced fluids

• All wells.

Table 8.B - Criteria For Use of SCSSV's 8.2.5.

Valve Type/Closure Mechanism Selection This section gives recommendations on the choice of valve with the corresponding type of closure mechanism. Note:

All valves with ball type closure mechanisms are not recommended for use as they are less reliable than flapper valves.

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Type of Valve

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Applications

Tubing Retrievable Flapper Valve

• • • •

Wireline Retrievable Surface Controlled Flapper Valve

• As on insert valve for tubing retrievable SCSSV’s.

Storm Chokes

• As a backup to the WRSV above when there is a control line failure. Set in the next lowest wireline nipple.

Annular Safety Systems

• Gas lift wells. • ESP wells with gas venting. • Jet pump wells, under the pump.

Wireline Retrievable Injection Valves

• All waste wells.

Offshore platform wells. Subsea wells. Wells with the presence of H2S or CO2. Wells with surface flowing temperature greater than 130°C. • Wells with shut-in surface.

Table 8.C - SSSV Closure Mechanism Applications Gas or water injection wells may have either a tubing retrievable or wireline retrievable SCSSV. 8.3.

CONTROL/INJECTION LINE SELECTION The purpose of this sub-section is to define the basic criteria for the selection and the use of small diameter tubes for SCSSV control line and injection line applications. These two different cases will be considered separately below.

8.3.1.

Control Lines Tube used as ‘control line’ to operate downhole safety valves are installed along with the production string. In this case, SCSSV’s are usually set at shallow depths and, therefore, the length of line required is generally relatively short.

8.3.2.

Injection Lines Tube used as ‘injection lines’ to inject chemical products such as corrosion or scale inhibitors down hole or as deep as possible in the well, are also installed with the tubing string. The line length required in this case, will be considerably longer.

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Tube Specifications Size Small diameter tubes for control or injection line applications are manufactured either as seamless or seam-welded and sunk. They are usually available in a full range of materials and sizes. In the seamless tube manufacturing process, the raw material comes in the form of extruded hollows, which are then reduced to the desired diameter and wall thickness by a cold drawing operation. In the case of welded tube process, the raw material comes in strips which are first rolled into tube form which is fed through a welding head to perform a fusion weld. The cycles of cold drawing with a floating plug drawing method is preferred and annealing operations performed to reach the desired dimensions and produce a weld zone homogeneous with the rest of the tube material. Welded tubes are considered the norm as opposed to seamless which are considerably more expensive and limited in length (usually a max. of 1000 ft in length). Welded tubes can be produced in extra long coils more than 3200 ft by butt welding lengths of tubings together. Both types of lines comply with ASTM specification A269 ‘Seamless and Welded Austenitic Stainless Steel Tubing for General Service’ and ASTM-B751 specification ‘General requirement for Ni and Ni alloy Seamless and Welded Tube’. 1

The standard size for both applications, control and injection line, is /4” OD and the wall thickness chosen from among the following sizes according to the pressure requirements: • • •

1

/4” OD x 0,035” wall thickness /4” OD x 0,049” wall thickness 1 /4” OD x 0,065” wall thickness. 1

Control Line Working Pressures A down hole safety valve is usually set at a relatively shallow depth, ranging about 30m to 50m from well head for on-shore installations or from sub sea level in case of off-shore activity. For this reason the configuration of the control line is not effected by the well deviation, therefore in most cases external encapsulation it is not recommended. Once the working pressure has been defined as explained in the following paragraph, refer to table 8.d for the selection of the size which most suits the requirements. The working pressure (WP) is defined as follows: WP = Safety Valve WP + Valve Opening Pressure Safety Valve WP is as specified by the manufacturer. Valve Opening Pressure, provided by the manufacturer, is the pressure required to overcome the closing force of the spring plus resistance due to friction effects. Usually it ranges between 1,500 to 2,000psi depending on the manufacturer.

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Chemical Injection Line Working Pressures Chemical injection lines are run to injection mandrels which are installed as close as possible to the bottom of the tubing. The definition of working pressure is based on the following considerations: • • • •

Well configuration, therefore total vertical depth. Injection fluid characteristics such as density and viscosity. Injection rates to choose the correct diameter and evaluate friction losses. Total pressure required to inject chemicals through the line.

Injection rates referred to in this application are always low, therefore the flow profile can be assumed to be laminar. Once the friction losses for laminar flow have been calculated then the diameter size can be determined accordingly. figure 8.n shows the graphs of pressure losses per 100m versus flow rate plotted for various internal diameters and various values of fluid viscosity. Once the working pressure has been defined as explained below, (Refer to table 8.d), the selection of the tubing size to meet with requirements can be made. Working pressure is defined as follows: WP = BHSP + Pfr − Phd Eq. 8.A where:

WP = BHSP= Pfr = Phd =

BHSP + Pfr - Phd Bottom hole static pressure. Friction losses (see figure 8.n). Hydrostatic pressure of injection fluid.

The pressures given in the table are computed with ultimate and yield tensile strength values given in table 8.f and they are rated to temperatures between -20 and 100°F. Values obtained are based on the Lamè’s formula for thick section pipes using internal pressure only and stress defined at the internal diameter face, combining radial and tangential stress to determine an equivalent resultant using the Von Mises Theory of Distortion Energy:

 OD  2  Ys   − 1  ID   P= 4  OD  3x  +1  ID  Eq. 8.B Variables are defined as: P Ys Ys WP OD ID

= = = = = =

computed pressure (psi) ultimate tensile strength to compute ‘Burst Pressure’ (psi) yield strength (2% offset) to compute ‘Test Pressure’ (psi) 80% of test pressure (psi) outside diameter (in) inside diameter (in)

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Type of alloy

OD (inch)

Wall (inch)

WP (psi)

Burst (psi)

Test (psi)

AISI 316 L

0.250

0.035

5.328

18.646

6.659

0.250

0.049

7.118

24.914

8.898

0.250

0.065

8.809

30.831

11.011

0.375

0.035

3.651

12.780

4.564

0.375

0.049

5.004

17.515

6.255

0.250

0.035

5.967

18.646

7.459

0.250

0.049

7.972

24.914

9.965

0.250

0.065

9.866

30.831

12.333

0.375

0.035

4.089

12.780

5.112

0.375

0.049

5.605

17.515

7.006

0.250

0.035

7.459

22.642

9.323

0.250

0.049

9.965

30.252

12.457

0.250

0.065

12.333

37.438

15.416

0.375

0.035

5.112

15.518

6.390

0.375

0.049

7.006

21.268

8.757

0.250

0.035

12.786

31.965

15.983

0.250

0.049

17.084

42.709

21.355

0.250

0.065

21.142

52.854

26.427

0.375

0.035

8.763

21.908

10.954

0.375

0.049

12.010

30.025

15.013

Monel K400

Incoloy 825

Inconel 625

Table 8.D - Theoretical Working, Bursting and Testing Procedures (for welded stainless steel tubing at between -20°F to 100°F) 8.3.4.

Material Selection Among the stainless steels and nickel alloys available, the most commonly used for control or injection line applications are listed in table 8.e together with their relative characteristics. Compatibility of packer or completion fluid with the selected material must be confirmed by means of condition specific laboratory testing. table 8.f shows the mechanical properties of these materials in the annealed condition.

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Type of Alloy

Main Characteristics

AISI 316 L

Is an austenitic stainless steel with reduced carbon content. Has good resistance to grain boundary attack and improved resistance to pitting and crevice attack. It is susceptible to chloride stress cracking when the presence of stress is combined with a packer fluid containing chlorides.

Monel K400

Is a nickel-copper alloy resistant to corrosion and stress corrosion over a wide range of conditions.

Incoloy 825

Is an austenitic nickel-base alloy with good resistance to pitting in chloride solutions and to stress corrosion has improved resistance to corrosion by many acids.

Inconel 625

Is a Nickel-base alloy with a higher percentage of molybdenum to give the highest resistance to chloride attack.

Table 8.E - Stainless Steels and Nickel Alloys Most Commonly Used Once the type of material to be used has been defined, based on pressure ratings and working environment, the corrosion department should be consulted to confirm compatibility with the packer fluids. Control or Injection line made of the above material shall comply with the following ASTM specifications: AISI 316L Monel K400 Incoloy 825 Inconel 625

-

In accordance with ASTM specification A269 (TP316L). In accordance with ASTM specification B165. In accordance with ASTM specification B423. In accordance with ASTM specification B704.

Type of Alloy

Tensile Strength (psi)

Yield Strength at 0.2% Offset (psi)

AISI 316 L

70,000

25,000

Monel K400

70,000

28,000

Incoloy 825

85,000

35,000

Inconel 625

120,000

60,000

Table 8.F - Nominal Mechanical Properties in Annealed Conditions (For temperatures between -20 to 100°F)

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Fittings Connections for either SCSSV control lines or chemical injection lines shall be performed as follows: •

In case of pressure rating < 5000 psi, line connections shall be of the ‘Swagelok’ type. • In case of pressure rating > 5000 psi, line connections shall be of the ‘Autoclave’ type as recommended by API Spec. 6A (Wellhead & Christmas Tree Equipment) at the paragraph ‘Equipment specification requirement’ under ‘test and gauge connections’. It is suggested to avoid, as far as possible, any intermediate connections to reduce potential leak paths. 8.3.6.

Protectors Control line protectors are designed to support and avoid (bare or encapsulated) crushing at where it is most exposed, e.g. where it crosses large offsets like couplings, downhole safety valves or gas lift mandrels. Protectors shall be designed for small annular clearances allowing sufficient annulus flow area. They should be of the “one piece” type without loose parts and designed so as to be quickly installed and removed. ‘Across coupling tubing protectors’ are recommended for use with both SCSSV control and injection lines applications. For control lines used on SCSSV’s installed at shallow depth (less than 250m), other types of protectors may be used. In general, ‘steel banding’ or ‘banding straps’, ‘rubber based’ and ‘mid joint protectors’ shall be avoided at all costs. The following technical requirements will identify protector performance: • • • • •

Material shall be of all metal construction. No structural welding shall be allowed. Lab corrosion tests shall be run to verify compatibility with annular environment. Capable of firmly supporting bare or encapsulated lines when performing completions and recovery during workover allowing control line and protector reuse. Force indicated in ‘l’ or ‘tons’ that the protector will support against axial displacement without failing or damaging the supported line. Force stated in ‘lb’ or ‘Kg’ that protector will resist as a direct pull on supported line without any slippage. Maximum load expressed in ‘lb’ or ‘kg’ that protector will withstand when contacting the casing wall without damage.

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Encapsulation Encapsulation of this line is recommended only for chemical injection lines applications. Encapsulation increases crush resistance during installation, protects line against abrasion, pinching and improves clamping profile. Several encapsulation materials are available, covering a wide range of environmental conditions. table 8.g indicates the compatibility of the main encapsulation materials with the most commonly used packer/completion fluids. In some cases, braided wire is placed alongside the injection line and bonded together by the encapsulation material, to further enhance resistance and strength avoiding any rolling and twisting tendencies (Refer to table 8.h). The following laboratory tests are suggested to confirm the lines mechanical characteristics and compatibility of the encapsulation material with the packer fluid used: • • • • • •

Immersion test of the encapsulated line in downhole conditions for a defined period of time. No evidence of a change in physical appearance should be observable. Gas impregnation tests at various temperatures, pressures and with various gasses for a fixed period of time. No evidence of cracking, blistering or embrittlement should be observable. Combined brine/sour gas exposure tests according to the operating conditions, as above. Combined crude oil/sour gas exposure tests according to operating conditions as above. Abrasion resistance test to compare the resistance against abrasion between bare and encapsulated lines. Crush resistance test by loading the tube laterally, across the diameter, simulating various loading levels, until tube collapse is evident. Encapsulated line results should be compared to bare line tests.

The following table 8.g shows the main properties of the most common types of encapsulation material available. The choice of material, is mainly based on type of packer fluid, well deviation and working temperatures to be experienced and shall be confirmed by laboratory tests for compatibility.

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Encapsulation Material

Main properties

Nylon

Compatible with diesel packer fluids containing high gas percentages. Nylon should not be used with completion fluids that contain calcium chlorides, calcium bromides or zinc bromides at high temperatures. Its maximum temperature rating is 250°F.

Santroprene

Compatible with most packer fluids with the exception of diesel or fluid at high gas concentration. Maximum operating temperature rating is 275°F - 300°F.

Halar

Chemically resistant to almost all downhole fluids. Excellent mechanical strength and abrasion resistance. Compatible with high gas content environments. Recommended for highly deviated wells. Maximum operating temperature is 400°F.

Rislan II


Foraflon PVDF


Table 8.G - Compatibility and Characteristics of Encapsulation Materials Halar (fluoropolymers) is a registered trademark of Ausimont USA Santoprene (thermoplastics rubber) is a registered trademark of Monsanto Rilsan II (polyamide thermoplastic) Foraflon PVDF (polyvinylidine fluoride thermoplastic material) Samples of different types of encapsulated tubes have been tested under compressive, laterally applied, loading simulating possible damage arising during installation to determine the tube crushing resistance and extend of polymer damage, (see Table below).

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Sample Size

Applied load in metric tons (no damage detected)

100mm - 1/4” OD x 0.049” Alloy 825 bare line 100mm - 1/4” OD x 0.049” Alloy 625 bare line 100mm - 1/4” OD x 0.049” Alloy 825 encapsulated with Foraflon: size 15mm x 12mm

2.45

Applied load in metric tons (line partially crushed, fluid flow not interrupted) 3.5

2.65

3.8

7.0

9.0

Table 8.H - Crush Resistance Test For Encapsulated Injection Lines 8.3.8.

SCSSV Hydraulic Control fluid The criteria in this section is for SCSSV control line applications only. Today hydraulic fluids are almost exclusively based on mineral oils. Other types of synthetic based oils, are employed only when operating temperatures are very low and special thermal standby properties are required. Most of the synthetic based oils used are of the flash fire resistant category as they have a very low pour floc point combined with a good performance at higher temperatures. With regard to subsea completions, the control fluid is the same fluid as used for the Xmas tree controls. table 8.i shows the main properties of the recommended oils for control line applications. 8.13 and figure 8.n below shows typical friction losses of control line fluids.

Injected fluid viscosity = 5cP

Fri c. los ses psi /10 0m

100 90 80 70 60 50 40 30 20 10 0

O.D = 0,25 inches

0

1

2

3

4

5

6

7

8

9

10

Q injection - liters/hr

Figure 8.M - Fluid Friction Loss with 5cP Fluid

w.t.= 0,035 w.t.= 0,049 w.t.= 0,065

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Injected fluid viscosity = 1cP 20

Fric. losses psi/100m

18 16 14 12 10 8 6 4 2 0

O.D = 0,25 inches

w.t.=0,035 w.t.=0,049 0

1

2

3

4

5

6

7

8

9

10

w.t.=0,065

Q injection - liters/hr

Figure 8.N - Fluid Friction Loss with 1cP Fluid The above graphs are based on the following formula:

Pf =

Q x L xµ 612.95 Di 4 Eq. 8.C

where:

Pf = Friction losses (kPa) Di = Internal diameter (inches) L = Length (meters) µ = Viscosity (cP) Q = Flow rate (lt / min) kPa X 0.145 = psi

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Agip Arnica 32 (Petroleum based)

Agip OSO 32 (Paraffinic based)

Agip Betula S 32 (Synthetic based)

Viscosity at 40° C cSt

32

30

29,4

Viscosity at 100° C cSt

6,4

5,3

5,1

Viscosity index

163

110

98

Pour Point °C

-39

-30

-55

Flash point °C

202

204

206

0,865

0,875

0,841

-

-

-60

Density at 15° kg/l Floc point °C

Table 8.I - Properties of Recommended SCSSV Hydraulic Oils * cSt x Density = cp **Density variation = 0.00065 (kg/l) / °C For standard applications Agip Arnica 32 is recommended as it has better theological properties than OSO 32. Agip Betula 32 should be employed only when operating temperatures are very low as in Siberia where temperatures may reach -50°C. In order to avoid plugging of the control line while running in hole, testing and running procedure must be carefully programmed and hydraulic fluid may have to be flushed through a filtration unit, if required (usually 5 micron absolute).

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Control/Injection Line Selection Procedure Flow Chart

Figure 8.O - Control/Injection Line Selection Flow Chart

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WIRELINE NIPPLE SELECTION The nipples required for completion purposes are based on the results of the previous design stages. The aim of this section is to determine the type (selective or tapered) and configuration of the diameters in order to optimise access to the sump and prevent friction pressure drop. This must take into consideration all the diameter constraints imposed by the casing profile and completion characteristics. The nipples are selected based on those most commonly used by the company; and include the following models: Selective: • Halliburton (previously Otis) X, XN, R, RN The choice of the type of nipple is subject to the working pressure which characterises the completion (e.g. SCSSV or wellhead). X and XN nipples are used for working pressure < 10,000 psi, while R and RN types are used on all higher pressures. Tapered: • Baker F top no-go (AF-HF-VF) and R bottom no-go (AR-HR-VR). Like the case in selective nipples, the choice depends on the working pressure of the string configuration AF, AR (WP < 10,000 psi) HF, HR (WP between 10,000 and 15,000 psi) VF, VR (WP > 15,000 psi). The principal physical characteristics of a nipple are: • • •

Seal bore diameter No-go diameter, if applicable Lock mandrel OD (LMOD).

Data on all of these nipples can be found in the manufacturer’s current catalogue. Do not rely on data produced elsewhere or use old catalogues as changes to the nipple systems may have been made resulting in incompatibility.

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Tapered Nipple Configuration The configuration of the nipples begins at the top of the string and moves downwards towards the bottom or packer tailpipe. The following physical dimensional values are required: • •

Running clearance (RC) = 0.050ins No-go dimension (NGD) = 0.050ins for tubing OD < 3.313ins = 0.060ins for tubing OD < 5ins = 0.080ins otherwise

The first nipple, generally in the tubing hanger, is always a Baker type F and is chosen with the maximum diameter available for the size of the completion tubing below the hanger. For the lower nipples, the minimum top and bottom restriction dimensions are determined by the following procedure: 1)

The top restriction (RA) is the minimum upper diameter of the nipple, chosen from one of the following: • • • • •

2)

ID of the packer Drift of the tubing ID of the safety valve Vertical access of the wellhead Sealbore diameter (top) or no-go ID (bottom) of the upper nipple.

The bottom restriction (RB) is determined by the ID of the SCSSV tubing-retrievable, and the only one used. At this stage a hypothesis of seal bore diameter of the nipple (SB) is determined by analysing the following conditions: If RB is not defined, or: RB > RA or (RA - RB > NGD + RC) then: LMOD = RA - RC SB = LMOD - NGD

3)

In other cases, the previous conditions are re-applied, decreasing the NGD to adjust the calculations. The minimum values which can be reached by the NGD are: • • •

4)

0.042ins for tubing OD < 3.313ins 0.050ins for tubing OD < 5ins 0.070ins otherwise.

The data obtained are then used to match the nipple. To select the nipples to be as compatible as possible with the available options in the suppliers catalogues, an approximation of 1/100ins for SB is acceptable.

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1)

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In the event of achieving a good match, the nipple is compared with the data from the catalogue. If there is no nipple with the characteristics required, there are two options: • •

2)

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Produce a new nipple size Select the maximum nipple diameter from the catalogue < SB.

The type of nipple (e.g. F) is obtained from the previous selection. If F is chosen, it is then possible to use an R type nipple if the following conditions exist: • •

The nipple in question is not required for the installation of a W/L retrievable backup SCSSV The subsequent nipple must be type F with the following characteristics:

SB(F) < SB(R) LMOD(F) + 0.050 < no-go ID(R). 8.4.2.

Selective Nipple Configuration Criteria similar to those detailed in the tapered nipple procedure are used to choose the tubing hanger nipple, i.e. the maximum diameter nipple which is compatible with the rated pressure of the Christmas tree is selected. For the subsequent nipples, the previous size is selected but only for a maximum of three nipples in series. After this it is necessary to reduce the diameter again. It is a rule that if the spacing between two successive nipples is < 30m, a tapered nipple will be used.

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PERFORATING The objective of perforating a well is to establish communication between the wellbore and the formation by making holes through the casing, cement and into formation in such a manner so as not to inhibit the inflow capacity of the reservoir. To optimise perforating efficiency, it is not solely down to the perforating technique but relies extensively on the planning and execution of the well completion which includes selection of the perforated interval, fluid selection, gun selection, applied pressure differential or underbalance, well clean-up, and perforating orientation. One of the important aspects is the underbalance, which has been proven to significantly help to achieve a post-perforating flow rate to effectively flush out gun debris and remove the crushed zone which surrounds every perforating tunnel. If this is not effective, increased perforating skin can reduce production rates. The advantages of perforated casing wells is already described in section 5.2.3 and offers selectivity, however the perforated volume in the pay is relatively small compared to open hole (+/- 25%), therefore perforation damage is an extremely important aspect. To this end it is necessary to obtain an adequate shot density with a sufficiently deep enough penetration to pass through the drilling damage and maximise flow through each tunnel.

9.1.

SHAPED CHARGE PERFORATING The principle of shaped charge perforating is available in any service providers sales and technical literature (Refer to figure 9.a). The important issues for the completion engineer are the charge selection to meet with the conditions and provide the maximum perforating efficiency. o

The explosives for use in most shaped charges up to 300 F is RDX (cyclonite) and above this temperature and depending on time exposed to the temperature, HMX, PS, HNS or PYX is used. The performance of each is available from the suppliers. The detonating cord, which couples all the charges to the detonator in the firing head, must match the explosive selected. The detonator is triggered by electrical heating when deployed on wireline systems or by a firing pin in mechanically or hydraulically operated firing head systems employed on tubing conveyed perforating (TCP) systems.

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Figure 9.A- Perforation Process 9.2.

GUN TYPES There are four main types of perforating guns: • • • •

9.2.1.

Wireline Conveyed Casing Guns Through-tubing Hollow Carrier Guns Through-tubing Strip Guns Tubing Conveyed Perforating Guns.

Wireline Conveyed Casing Guns These types of guns are generally run in the well before installing the tubing, therefore no underbalance can normally be applied although in large size monobore type completions some sizes can be run similar to through-tubing guns using an underbalance. The advantage of casing guns over the other wireline guns are; high charge performance, minimal debris, low cost, highest temperature and pressure rating, high mechanical and electrical reliability, minimal casing damage, instant shot detection, multi-phasing, variable shot densities of 1-12spf, speed and accurate positioning using CCL/Gamma Ray.

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Figure 9.B - Types of Guns

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Through-Tubing Hollow Carrier Guns These are smaller versions of casing guns which can be run through tubing, hence have o lower charge sizes and, therefore performance, than all other guns. They only offer 0 or o 1 7 180 phasing with a max. of 4spf on the 2 /8” OD gun and 6spf on the 2 /8” OD gun. Due to the stand-off from the casing which these guns may have, they are usually fitted with decentralising/orientation devices.

9.2.3.

Through-Tubing Strip Guns These are semi-expendable type guns and consist of a metal strip into which the charges are mounted. The charges have higher performance and are much cheaper than throughtubing carriers guns, however they also cause more debris, casing damage and have less o o mechanical and electrical reliability. They also provide 0 or 180 phasing. A new version called the ‘pivot gun’ has even larger charges for deep penetration which pivot out from a vertical controlled OD to the firing position. Due to the potential of becoming stuck through strip deformation, they must have a safety release connection so they can be left in the well. They have a particular application for perforating through DST strings and reperforating completed wells. By being able to be run through the tubing, underbalance perforating can possibly be adopted but only for the first shot. Subsequent runs would need the well to be flowed to cause a differential pressure.

9.2.4.

Tubing Conveyed Perforating TCP guns are a variant of the casing gun which can be run on tubing, therefore, allowing much longer lengths to be installed. Lengths of over 1,000ft are possible (and especially useful for horizontal wells) and perforating under exceedingly high drawdowns is possible with no risk to the guns being blown up the hole. In completion operations, they may be deployed and hung-off in position before installation of the completion string, run on the bottom of the completion packer or run through the tubing on coiled tubing. Alternately they can be run in long lengths for overbalance perforating before completion string installation. Normally the completion is displaced to an underbalance fluid, then the guns detonated by either: • • • •

A bar dropped from surface Hydraulic pressure applied from surface then subsequently reduced to the planned underbalance pressure during a time delay. Hydrostatic pressure reduction. Impact by a wireline deployed tool.

Another version available, normally used on well tests, is where a differential is applied between the annulus and the sump via porting through the test packer.

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The main problems associated with TCP are: • • • •

Gun positioning is more difficult The sump needs to be drilled deeper to accommodate the gun length if it is dropped after firing A misfire is extremely expensive Shot detection is more unreliable.

Due to the longer exposure time because of the deployment, higher grade charges may also be required. 9.3.

GUN PERFORMANCE

9.3.1.

API And Performance Data For most completion applications, API RP 43, which includes performance data produced by the suppliers, can be used as a qualitative comparison of charge performance. This provides under two specific tests: • •

Entrance hole size and penetration length into a 5ft diameter concrete target. Entrance hole, penetration and flow efficiency in a Berea sandstone target at elevated temperatures and an estimated 800psi effective stress.

The performances are listed in two sections I and II. Section II is normally used for comparisons, however the performance in actual use may differ due to differences in rock strength, overburden stress and wellbore pressure and temperatures. The variations for these reasons is non-linear and depends on the type of charge. The API tests are also unreliable as the targets have had differing strengths and porosities and there is no consistent quality control standard for production of the charges. Ageing of explosives, charge alignment, moisture contamination, gun stand-off, the thickness of casing and cement or if multiple casings are to be perforated also has an impact on the gun performance. It is necessary for engineers to obtain as much accurate data from the suppliers and use Eni-Agip historic data in order to be able to make the best choice of gun.

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Guidelines Gravel Pack Completions Due to the problem of flow restriction discussed earlier in section 2.4.1, the important factors are: • • • • •

Hole diameter to achieve adequate flow area. Shot density to achieve adequate flow area. Debris removal. Shot phasing. Penetration.

This in conjunction with correct gravel pack procedures is essential for to prevent high skin factors. High Underbalanced TCP Perforating High drawdowns over 500psi for production wells require, if possible: • • • •

TCP methods Deep penetrating charges. High shot density over 8spf. o Minimum 90 phasing.

Underbalanced Perforating With Through-Tubing Guns If TCP costs cannot be justified and if formation perforated skin factor is acceptable, underbalanced perforation can be carried out with through tubing systems. On the first run a high overbalance can be used but on subsequent runs the only means of producing a differential is to flow the well at a rate governed not to blow the gun up the hole. This is affected by the gun weight, type of fluid, bypass area and expected flow rate. The use of these relatively smaller guns require contact with the casing wall, orientation at o o o 90 with 180 phased guns or in line with the contact point if 0 phased. Shot Density Shot density in homogeneous, isotropic formations should be a minimum of 8spf but must exceed the frequency of shale laminations. If perforating with through-tubing guns, this will require multiple runs. A shot density greater than this is required where: • • • •

Vertical permeability is low. There is a risk of sand production. There is a risk of high velocities and hence turbulence. A gravel pack is be conducted.

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Penetration In general, the deeper the shot the better, but at the least it should exceed the drilling damage area by 75mm. However, to obtain high shot density, the guns may be limited to the charge size which can physically be installed which will impact penetration. Phasing o

o

o

o

Providing the stand-off is less than 50mm, 180 or less, 120 ,90 , 60 is preferable. If the smallest charges are being used then the stand-off should not be more than 25mm. If o fracturing is to be carried out then 90 and lower will help initiate fractures. Gun Stand-Off Gun stand-off should be minimised for improved performance, especially at high pressures. If low phase angle, high density shots are preferred then TCP and casing guns should be used. As a general rule stand-off should never be more than 50mm. Hole Size The hole size obtained is a function of the casing grade and should be as follows: • • •

Between 6mm and 12mm for natural completions. Between 15mm and 25mm in gravel packed completions. Between 8mm and 12mm if fracturing is to be carried out and where ball sealers are to be used.

Overbalanced Perforating If a well is to be perforated overbalanced, then strict control over the fluid used to ensure it is compatible with the reservoir formation, formation fluids and must also be clean to prevent formation damage. 9.3.2.

Underbalanced Perforating To optimise the perforating clean up, an underbalance should be used. King et al developed a recommended minimum level of drawdown based on a number of field studies where TCP perforating had been employed, (Refer to the Figures below). These guidelines should be used to select the appropriate drawdown for consolidated completions. In unconsolidated sands, the intention is to cause perforation enlargement to remove the crushed zone without collapsing the cavity or sanding in the guns. This requires that less drawdown is exerted during the well clean up. The optimum clean up period is subjective and opinions range from 1gall to 5gall per perforation. The best method of clean up is to flow the well continually for several hours after perforating at normal offtake rates.

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Firing Heads As described earlier, there are a number of different firing heads for various applications. . Wireline perforating systems are normally electrically trigger by passing an electrical signal down the cable to the guns. However, in TCP systems there are a wide variety including pressure operated, bar drop, wireline activated, etc. Two very important considerations are safety during installation of TCP systems and redundancy in the event of a fault occurring in the primary firing system. Safety The use of tubing installed hydraulic actuated systems has the problem of how to conduct pressure integrity tests on the completion with sufficient margin between the gun activation pressure and the highest test pressure applied. Obviously, it is undesirable to have a gun actuation pressure higher than the test pressure as a leak may occur while trying to trigger the guns. Protecting the firing head from test pressure is a dangerous procedure as a plug may leak will also cause premature detonation. It is good practice to use a bar drop firing mechanism (deployed on wireline if possible as dropping the bar from surface may damage sensitive completion items) or wireline installed firing heads which can be installed after the completion is set and tested. This provides full safety during gun deployment. Redundancy This is an important aspect, for if there is a firing head fault, gun recovery would be very costly. Using wireline installed firing heads provides some redundancy in that the first head can be retrieved and a second head deployed. There are other side-by-side systems available which provide a tubing installed pressure activated firer with a secondary receptacle for a wireline installed firer.

9.3.4.

Perforating Procedures Refer to the ‘Completion Procedures Manual.

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Figure 9.C - Recommended Underbalance for Perforating Gas Zones in Stable Sandstones

Figure 9.D - Recommended Underbalance for Perforating Gas Zones in Stable Sandstones

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Figure 9.E - Recommended Underbalance for Perforating Shallow Unconsolidated Gas Sands

Figure 9.F - Recommended Underbalance for Perforating Shallow Unconsolidated Oil Sands

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ARTIFICIAL LIFT The benefits and most commonly used artificial lift were described previously in section 5.6.4. The application of artificial lift simply displaces the TPC curve downwards so that a lower bottom-hole flowing pressure is achieved. In simple terms, the artificial lift injects energy into the system. Energy can also be introduced by reservoir pressure maintenance. Reservoir development optimisations studies are necessary to determine the relative technical and economic benefits of the options and the timing of the investments. In some fields, both pressure maintenance and artificial lift are used which defers the installation. In other cases, artificial lift from the outset is necessary to achieve the production and economic targets. Just as tubing size is critical to high PI wells, then minimisation of the FBHP is critical to low PI, low pressure wells. To summarise the reasons for the installation of artificial lift are to: • • • • •

Reduce the effects of declining bottom-hole pressures. Offset the effects of increasing water production. Overcome high friction effects of heavy viscous or waxy crudes. Meet with targeted high offtake rates. Kick off high GLR wells that die when shut-in.

The selection of the most appropriate artificial lift system involves a number of factors but mainly on specific well performance. Section 10.7 lists all the systems, their applications, design considerations, limitations and comparisons. Selection of the method is also based upon operating costs and workover frequency costs. System life is difficult to predict as it is a function of operating conditions, e.g. ESP life can vary between days and five years depending on temperature, solids production, GLR and lack of particular experience with the system. Some systems are able to cope better with production problems than others which will obviously affect the choice. Consideration of future artificial lift requirements must be taken during the planning stage, such as casing size, liner top setting, etc. These early decisions can save much expense later, such as: • • • • • • • •

Casing ID Casing connection in on gas lift Size and positioning of liners Provision of a sump for rod pumpers Pre-positioning of gas lift mandrels for gas lift and ASV system Pre-installation of conduits for hydraulic pumps Parallel bore for plunger lift etc.

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GAS LIFT The continuous gas lift method adds gas into the producing fluids which reduces the hydrostatic head and, hence the back-pressure on the formation. The injection gas is supplied in a closed loop system in which it is taken from the separators and then compressed, dried if necessary and then delivered to the well (Refer to figure 10.a). The lift gas is normally pumped into the annulus and into the tubing through gas lift valves installed in Side Pocket Mandrels (SPMs). Occasionally the gas is pumped into the tubing and the production taken up the annulus or in the annular space in a concentric completion. Another less common application is Intermittent Gas Lift, also shown in figure 10.a, which is used to produce low volumes of liquid (<350stb/d) from wells with low BHFP (<0.1psi/ft). Due to the low liquid production, it must be produced in slugs by intermittently gas injection through a motorised valve. A standing valve is sometimes necessary to prevent the gas from flowing into the formation. In continuous gas lift, it is desirable to position the lower gas injection point as deep as possible in the well, however this is limited by: • • • •

available gas lift pressure the flowing tubing pressure at the intended offtake rate the depth of the packer and deepest gas lift mandrel the differential required to close the upper valves closed (+/-20psi) and to ensure that injection at the operating GLV is stable (between 50 and 500psi)

figure 10.b illustrates the fundamental principle of a gas lift design and operation. As can be seen the gas is injected down the annulus and into the tubing through the topmost valve lightening the fluid column in accordance with the total GLR curve shown. As the fluid gradient changes, the gas moves down to the next valve unloading the casing fluid and as the reaches the second valve and lightens the fluid gradient from that point, the first unloading valve closes so that all the gas passes through the second valve. This continues in sequence for all other valves until reaching the operating valve where the casing pressure will drop below the initial kick-off pressure. During this process the well BHP will drop to the point where the well will flow. Production is determined by: • • • •

reservoir pressure PI water cut gas injection rate

Once the well reaches a stabilised rate, the injection is optimised to maximise production. As described in section 2.4.3, increasing GLR initially decreases the bottom-hole pressure on the TPC. There is an optimum GLR to produce stabilised flow for a particular tubing size and a minimum BHFP. As GLR requirements are subject to diminishing returns, most gas lift systems are based on available gas supply volumes, Qi, or either the near optimum GLR which provides a BHFP within 20-50psi of the minimum.

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From this it is seen: • • •

Liquid rate, q, is dependent on the IPR and attainable BHFP. Total GLR = Producing GLR + Injection GLR
Figure 10.A - Typical Gas Lift System

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Figure 10.B - Example Gas lift design 10.1.1. Impact On Completion Design In recent times, much higher gas supply pressures have been used to enable deeper valves to be reached or reduce the number of mandrels and valves required. This increased pressure, however, applies more pressure on the annulus casing, hence gas tight or premium connections are generally selected. Modern gas lift systems usually now use SPMs with wireline GLVs to reduce servicing costs. SPMs have relatively large ODs and this needs to be considered in the casing design. All mandrel depths are taken of the design as TVDs and these must be converted to MD. As the mandrels at deeper depths become increasingly closer, the spacing of them is much more critical. Although gas lift valves incorporate check valves to prevent back flow, these are not reliable and as the annuli contain quite a considerable inventory of gas, an annulus safety system is installed for platform safety. This may again impact on the casing design.

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10.1.2. Common Problems The worst problem that can arise is that the pressure losses in the gas injection system and slugging have been underestimated and that the valve spacing is too far apart. Operationally, the problems are usually inefficiency through upper gas lift valve or tubing leaks. 10.2.

ELECTRICAL SUBMERISBLE PUMPS ESPs greatest application is in moving large volume of low GOR (<100scf/stb) fluids. They are particularly popular for high rate undersaturated oil wells, high water cut wells and water supply wells. Their main limitation is gas production but improved downhole separators and procedures can now handle GORs up to 1,000scf/stb. ESPs performance is best at stable conditions within +/-25% of the optimum rate. Versions with variable frequency drives (VFD) are available or the use of surface chokes can be used to increase the band of rate (50-190%) but incur higher capital and operating costs. The construction of the ESP is a multi-staged centrifugal connected through a short shaft to the downhole electric motor. Each stage consists of a rotating impeller and stationary diffuser. The differential pressure or total dynamic head (TDH) developed by the pump is a function of the pump flow rate which is relative to the head developed by each stage and obtainable from manufacturers publishing’s. TDH=Ns Hs

Eq. 10.A

where: NS HS

= =

number of stages head per stage

The pump characteristics are based on constant rotational speed which is dependent on the AC supply frequency, 3,500 rpm at 60 Hertz and 2,915 at 50 Hertz. Due to these high speeds and pump construction it is obvious that sand production is very detrimental and that emulsions are easily formed. To prevent sand production it is sometimes necessary to install a gravel pack or pre-packed screen for pump protection. The ESP delivery capacity will vary according to: • • • •

Well IPR Reservoir pressure Surface back-pressure Electrical supply frequency

figure 10.c shows the most common types of ESP installations and the pump components. Surface equipment usually includes a three phase transformer, motor controller and a wellhead pack-off for the cable. If possible, the installation should be designed to facilitate downhole separation of free gas and vented up the annulus which is necessary when the gas volume exceeds the pump operating limit (typically +/-10% of the total fluid volume). On offshore installations, gas production up the annulus may be a significant problem.

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As can be seen from the schematic, most pump installations are on the end of tubing and positioned above the perforations or open hole. The motor is situated at the bottom of the assembly so that the well flow around the motor will dissipate the heat generated. If the pump has to be positioned below the interval, a shroud is used to draw the produced fluid down past the motor. Bottom discharge pumps are used in powered dump flood wells.

Figure 10.C- Typical ESP Installations

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Other less common deployment methods are: • •

Suspended on the cable and latched into a downhole receptacle. On coiled tubing with the cable through the coil which is terminated with a special wellhead arrangement.

Both of these suffer from some problems such as cable failures with the cable suspension method and well control issues with the C/T mounted method (i.e. downhole safety systems if the well can flow naturally). A recent development with the later is in Norway where downhole safety is satisfied by the installation of shear seal capability below the coiled tubing hanger. 10.2.1. ESP Performance It is normal procedure to select the largest pump that will fit into the production casing (especially if this was catered for in the planning stage). Small casing or liners will obviously limit the pump size selection. ESP sizes and capacities are shown in table 10.j below.

Casing Size, ins

Pump OD, ins

Motor OD, ins

Rate, stb/d

Power, HP

TDH, ft

1

4 /2

3.375

3.750

100-1,900

50-125

5,000-12,000

1

5 /2

4.000

4.500

200-5,000

100-300

5,000-12,000

7

5.625

5.437

1,000-16,000

200-650

5,000-12,000

5

8 /8

6.750

7.375

4,000-26,000

400-850

3,000-10,000

3

8.625

N/A

12,000-33,000

500-1020

2,000-5,000

3

11.250

N/A

24,000-100,000

500-1030

500-3,500

10 /4 13 /8

Table 10.J - ESP Capacity Ranges Two approaches are commonly used to evaluate an ESP system: 1)

2)

Pre-select the production target and corresponding BHFP and determine the TDH and pump size and depth required to meet this rate. This often carried out by plotting the pressure traverses above and below the pump (Refer to figure 10.d). Pre-select the maximum pump horsepower, or number of stages, and determine the attainable pump rate with: • •

a fixed IPR and various tubing sizes a fixed tubing size and various IPR options

In this approach the pump performance curve is often plotted below the system performance curves. An example this to optimise the number of stages for a maximum pump HP is shown in figure 10.e.

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Figure 10.D - Example ESP Design for a Pre-selected Rate

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Figure 10.E- Example ESP Design for a Pre-selected HP

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10.2.2. Impact On Completion Design The key to an efficient ESP design is heat removal and insulation material selection for the actual operating temperatures and environment, especially when temperatures are in the o region of 250 F. The clearance between the pump and the casing should be small enough that a flow velocity of a minimum of 1ft/sec is achieved. In large casings, a shroud must be used to provide this rate. Centralisation of the pump is also critical. The pump should be set in a straight section of casing to avoid bending and the cable needs to firmly attached to the tubing for support by cable clamps (two per joint). Centralisation and crush resistant clamps should be installed across doglegs. When re-completing a ESP well the pump should be moved slightly from the original position to help minimise any casing corrosion due to eddy currents. Casing design is obviously has a large impact on the completion design or in the case of an ESP completion, vice versa. Also consideration must be given to the optimum tubing size and cable dimensions to ensure they can be accommodated in the casing. The completion design is also affected if downhole separation is required in conjunction with downhole safety. Tubing hanger and penetration systems for packers have been well developed now for fast easy installation with the testing of the connections carried beforehand in the workshop. If properly planned an ESP completion only requires one onsite termination. 10.2.3. Common Problems The biggest problem with ESP completions is short running time before failure with the cost impact for re-completion. However, ESP systems are becoming evermore reliable. The most common problems are due to: • • • • • • • •

Bad installation procedures. Inadequate system analysis leading to the system operating outside the range. Unsuitable cable insulation material for the conditions. Too much free gas and no enlarged intakes stages. Sand production. Too many frequent start ups when there is no soft start facilities. Scaling up of the impellers. Poor voltage supply stability.

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HYDRAULIC PUMPING SYSTEMS Hydraulic pumping systems are attractive alternative to ESP systems where there is high temperatures, depth, deviation or severe operating environments. The downside is the requirement for two reasonably large conduits to minimise fluid pressure losses, maintaining a clean solids free power fluid and the high capital and operating costs. It is also popular where there is insufficient gas for a gas lift system and is a viable alternative to rod pumps for deep (>8,000ft) wells. The two simplest and common systems are the Jet Pump and the Piston Pump which are interchangeable in most instances which provides great flexibility in coping with changeable well conditions. The pumps can be installed and retrieved by wireline or pumping method using swab cups, hence providing lower servicing costs. The conduits for the power fluid and returns can be the annulus with a single tubing, however this exposes the annulus to potential corrosion so, if this is a problem, dual tubing strings can be used either parallel or concentric. The annulus is sometimes required for gas venting and in this case a dual string is required. Piston Pump The piston pump is a reciprocating pump operated with a drive piston which automatically shuttles backwards and forwards exhausting the spent power fluid into the returns. In effect the piston pump is equivalent to the rod pump except that the pump drive is subsurface but can produce up to 8,000stb/d although it is normally used to produce <2,000stb/d. Their application is commonly for deviated wells between 8,000-18,000ft although high surface power fluid pressures are required below 12,000ft. There is flexibility in the system as pump rates are controlled by controlling the power fluid supply rate. There is a large selection of pump sizes/stroke length available for a wide range of operating conditions. Jet Pump The jet pump uses no moving parts and imparts momentum into the fluid using the venturi effect with a jet, throat and diffuser. The size of the these can be varied to pump volumes of 1 100-15,000stb/d although free pump systems are limited to 8,000stb/d with 4 /2” tubing. To prevent cavitation, it is recommended to submerge the pump by at least 20% of the TDH so is better suited to respectfully productive, or restricted offtake target wells. As there is no moving parts, the pump is not as sensitive to damage and lower quality power fluids can be used and can be used in higher GOR wells up to 3,000scf/stb. However pump efficiency is low at 33-66% and large production rates can only be achieved in high rate installations. Pump performance is a complex function of GOR, pump intake pressure, supply pressure and rate. Optimisation is generally through using supplier’s computer software. A preliminary calculation of the pump intake or output curve can be made by hand. The maximum attainable performance have been summarised in table 10.k below.

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Head Ratio

Flow Ratio

0.45

0.5

0.25

1.0

0.17

1.5

0.10

2.0

Table 10.K- Jet Pump Maximum Performance In table 10.k above: pump output pressure − pump inlet pressure downhole power fluid pressure − pump output pressure reservoir production rate Flow Ratio = power fluid rate

Head Ratio =

Often the maximum power fluid supply pressure and rate is fixed by surface equipment rating, e.g. p<5,000psi, qPF <4,500stb/d. When calculating bottom hole pressures, the completion configuration and power fluid rate to the production to obtain the total discharge rate. The pump intake curve (PIC) can then be generated using table 10.k above plotted against well IPR (Refer to figure 10.f).

Figure 10.F- Example Jet Pump Design Curve

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Turbine Pumps The hydraulic turbine pump developed by Weir Pumps is an alternative to the ESP for producing very large volumes of fluid, 2,000-100,000stb/d. It has the same principle of operation as the ESP but the motor is replaced by a hydraulic turbine which rotate the shaft at 5,000-10,000rpm. This provides higher lift capacities (head and volume) per stage, therefore the units are much shorter approximately 10% of the ESP. The operating range is much greater as the pump can be controlled by varying the supply pressure giving 10-100% rate and 20-50% TDH at reduced rates. Their reliability is still suspect due to the high rotating speed and metallurgy problems. 10.3.1. Impact On Completion Design The casing size is obviously important here to accommodate the pump size and perhaps two tubing strings. Sometimes concentric completions are preferred or the annulus is used but consideration must be given to potential corrosion due to oxygen in the power fluid. Like the piston pump solids free power fluid is essential. Like the ESP, gas venting may be necessary which would require a third conduit (generally the annulus). Occasionally the DHSV is controlled by pressure from the pump. 10.4.

ROD PUMPS The most common pumping system on low rate land wells is the rod or beam pumping. It is usually limited to shallow wells (<8,000ft) producing less than 500stb/d although they can produce up to 2,000stb/d. The system consists of three elements, the downhole pump assembly, the sucker rod and the surface pumping unit. The annulus is usually left open and used to vent any free gas that is separated downhole. Tubing is used as the production conduit and contains the rods preventing wear and corrosion to the annulus. The tubing is usually anchored to the casing and pulled into tension to reduce tubing movement, buckling and, hence rod wear. There are two versions of bottom-hole pump, the tubing retrievable barrel and the rod retrievable barrel. The tubing pump requires the tubing to be pulled to retrieve the barrel and the rod pump barrel is retrieved when pulling the rods. The tubing pump has the largest capacity but is more costly to repair than the rod pump which is the most common. The pump displacement, PD, is defined by the plunger stroke, SP, and the pump speed, N, the plunger diameter, D and the amount of liquid fillage and/or slippage past the plunger, EP = 0.7 to 9.5. 2

PD = Ct x Sp x N x D x Ep Eq. 10.B where: EP Ct

= =

Pump efficiency 2 Correction factor 0.1166 for oilfield units, (in, spm, in , stb/d)

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Figure 10.G- Typical Rod Pumping System

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As the rod suffers from stretch and dynamic forces, SP will not be the same as the stroke at surface, S, therefore load-displacement plot forms the basis for pump design and analysis. The fluid load, Fo, carried by the rods on the upstroke is dependent on the net lift, H, which is the vertical distance from the operating fluid level (OFL) in the annulus to surface plus the equivalent head of any surface back-pressure. It also depends on fluid SG or density. API recommends ignoring the area of the rods when calculating this load: 2

Fo = Ct x SG x D x H where: Ct

=

2

0.340 in oilfield units (SG, in , ft, lbs)

This load can be estimated from dynamometer surveys, which measure the rod load versus displacement at the surface and serves the most effective means of diagnosing pump problems. As the loads on the polished rod includes fluid load, dynamic forces and rod weight, the rod weights may be relatively large in deep wells and in these cases a tapered rod string is preferred where the rod diameter is larger with increasing load. Buoyancy varies throughout the cycle but it is generally taken on the downstroke when the travelling valve is open. Acceleration and friction are also factors in dynamic loading with the peak polished rod load on the upstroke will be significantly higher than the sum of the rod and fluid loads. Similarly, on the downstroke, the minimum will be less than the buoyant weight of the rods. Pump stroke efficiency is a function of pump speed and rod loading. The dynamics also cause the rods to oscillate harmonically like a stiff spring. Typical pumping speeds are 8 to 15spm which amounts to 4.2 to 7.9 million cycles per year, therefore the rod design must focus on minimising fatigue failures which is exacerbated by corrosion in the operating environment. The surface pump unit is usually a beam type although other concepts have been developed. The surface prime mover and gearbox have been developed over the years to cater for the rod pump to reduce failures. System design is very complex and is an iterative process normally carried out by computer software. API have produced a programme to generate a set of design curves published in API RP11L and provided some general results in Bulletins 11L3 and 11L4 which are a useful starting point for design. However, in 11L4, API used 100% efficiency and pump rates which are higher than those generally found in the field, therefore, it is advisable to enter a curve which is 100 to 200% of the intended target for scoping out the required o equipment capacity. It is also not reliable for heavy oil wells (<20 API) unless correction factors are applied for fluid vicosities and lack of rod weight on the downstroke. Rod fall problems often cut restrict pump rates to 1.5 to 2.5spm which lead the use of long stroke pumps. Sand problems are often a problem with high viscous crudes which increase wear of the pump parts.

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10.4.1. Impact On Completion Design If free gas is expected then a packer should not be installed to allow the gas to vent up the annulus if it is planned to convert a completion to rod pump lift within a few years unless required for zonal isolation. If a well has to be pumped which is below the bubble point, it is advised to set the pump below the producing interval to aid gas separation, maximise drawdown and minimise perforation blocking by fill. If a well is fractured, the pump must be set above the perforations as frac sand can damage the pump. The casing geometry must be sufficient enough to enable the gas to percolate through the fluid column against the down-flow. 10.5.

SCREW PUMP SYSTEMS Screw or progressive cavity pump is a rotary positive displacement pump consisting of a rubber stator and stainless steel rotor. The rotary drive to the downhole pump is through sucker rods from a prime mover through a gearbox. They rates of between 5 to 500stb/d, although in some circumstances capacities of 1,500stb/d is possible, on heavy oil wells or viscous emulsions where conventional rod pumps are hindered by rod fall. They have an advantage in that they can handle some sand production and less costly. The production rate is proportional to the rotary speed and are determined from manufacturers charts, generally between 50-100rpm in heavy oil and 500rpm in light oils. The selection of the material for the rubber stator is the key for operational life in the well environment.

10.6.

PLUNGER LIFT Plunger lift are used on high GLR wells that produce liquids at relatively low rates (<500stb/d). The tubing/casing annulus is used to store gas energy provided to the tubing when the well is opened up. This energy is used to drive the plunger up to surface carrying a small slug of liquid. After production of the following tail gas when the liquid begins to kill the well the plunger is dropped again and the cycle repeated. It is particularly useful for de-watering gas wells. Operating requirements are: • • •

GLR >500scf/stb PI <1stb/d/psi Plunger velocity 700 to 1,000ft/min

Efficiency of this system decreases with depth and PI but increases with tubing size. It is essential that the completion tubing is parallel and drifted to ensure correct operation of the plunger.

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Figure 10.H- Typical Screw Pump Installation

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Figure 10.I - Typical Plunger Lift Installation

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SUMMARY ARTIFICIAL LIFT SELECTION CHARTS

10.7.1. Design Considerations And Comparisons Consideration

Rod Pumping

Screw Pumping

ESP

Hydraulic Piston Pumping

Hydraulic Jet Pumping

Continuous Gas Lift

Intermittent Gas Lift

Plunger Lift

Capital Cost

Low to moderate increase with depth and larger units.

Low increase with depth and larger rates.

Relatively low capital cost if commercial electric power available. Costs increase as horsepower rises.

Varies but often competitive with rod pumps. Multiple well, central systems reduce cost per well but is more complicated.

Competitive with rod pump. Cost increases with higher horsepower.

Low well equipment costs but lines and compression costs may be high. Central compression system reduces cost per well.

Same as continuous flow gas lift.

Very low, only low cost well equipment if no compressor required.

Downhole Equipment

Reasonably good rod design and operating practices needed. Data bank of rod and pump failures beneficial. Good selection, operating and repair practices needed rods and pump.

Good design and operating practices needed. May have problems with selection of appropriate stator elastomer.

Requires proper cable in addition to motor, pumps, seats, etc. Good design plus good operating practices essential.

Proper design plus good operating practices essential. requires powerful conductor. Free pump and choose powerful option.

Requires computer design programme for sizing. tolerant to moderate solids in power fluid. No moving parts in pump. Long service life and simple repair procedures.

Good valve design and spacing essential. Moderate cost for well equipment (valves and mandrels). Choice of wireline retrievable or conventional valves.

Unload to bottom with gas lift valves. Consider chamber or high PI and low BHP wells.

Operating practices have to be tailored to each well for optimisation. Some problems with sticking plungers.

Efficiency (output hydraulic HP divided by input HP)

Excellent total system efficiency. Full pump fillage efficiency typically about 50-60% feasible if well is not over-pumped.

Excellent. May exceed rod pumps for ideal cases. Reported system efficiency 5070%. More operating data needed.

Good for high rate wells but decreases significantly for <1,000 BFPD. Typically total system efficiency is about 50% for high rate well but for <1,000 BID, efficiency typically is 40%.

Fair to good, not as good as rod pumping owing to GLR, friction and pump wear. Efficiencies range from 3040% with GLR >100. May be higher with lower GLR.

Fair to poor. Maximum efficiency only 30%. Heavily influenced by power fluid plus production gradient. Typically operating efficiencies of 10-20%.

Fair increases for wells that require small injection GLRs. Low wells for wells requiring high GLRs. Typical efficiencies at 20% but range from 5-30%.

Poor, normally requires a high injection gas volume/bbl fluid. Typical lift efficiency is 1050% improved with plungers.

Excellent for flowing wells. No input energy required because it uses the well. Good even when small supplementary gas is added.

Flexibility

Excellent, can alter stroke speed, length, plunger size and run time to control production rate.

Fair, can alter speed. Hydraulic unit provides additional flexibility but at added cost.

Poor. Pumps usually run at a fixed speed. Requires careful sizing. VSD provides more flexibility but added costs. Time cycling normally avoided. Must size pump properly.

Good to excellent. Power fluid rate and speed of downhole pump. Numerous pump sizes and pump/engine ratios adapt to production and depth needs.

Good to excellent. Can vary power fluid rate and pressure adjusts the production rate and lift capacity. Selection of throat and nozzle sizes extend range of volume and capacity.

Excellent. Gas injection rate varied to change rates. Tubing needs to be sized correctly.

Good, must adjust injection time and cycles frequently.

Good for low volume wells. Can adjust ingestion time and frequency.

Miscellaneous problems

Stuffing box leakage may be messy and a potential hazard. Anti-pollution stuffing boxes are available.

May have limited service in some areas. Because this a newer method, field knowledge and experience are limited.

Requires a highly reliable electric power system. Method sensitive to rate changes.

Power fluid solids control essential. Need 15ppm of 15µm particle size max. to avoid excessive engine wear. Must add surfactant to a water power fluid for lubrication. Triplex plunger leakage control required.

More tolerant of power fluid solids, 200ppm of 25µm particle size acceptable. Dilutents may be added if required. Power water (fresh, produced or seawater) acceptable.

A highly reliable compressor with 95+% run time required. Gas must be dehydrated properly to avoid gas freezing.

Labour intensive to keep time tuned otherwise poor performance. maintaining steady gas show often causes injection gas measurement and operating problems.

Plunger hangup or sticking may be a major problem.

Table 10.L - Design Considerations and Overall Comparisons (pg1)

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Screw Pumping

ESP



Continuous Gas Lift


Plunger Lift

Operating Costs

Very low for shallow to medium depth (<7,500ft) and locations with low production (,400BFPD).

Potentially low but short run life on stator or rotor frequently reported.

Varies, if HP is high, energy costs are high. High pulling costs result from short run life. Other repair costs are high.

Often higher than rod pump even for free systems. Short run life increases total operating costs.

High cost owing to HP requirement. Low pump maintenance cost typical with properly sized throat and nose.

Well costs low. Compression costs vary on fuel cost and compressor maintenance. Key is to inject as deeply as possible with optimum GLR.


Usually very low,

Reliability

Excellent. Run time efficiency >95% if good operating practices are adopted and corrosion, wax asphaltenes, solids, deviations, etc., are controlled.

Good. Normally over-pumping and lack of experience decreases run time.

Varies. Excellent for ideal gas lift cases, poor for problem areas. Very sensitive to operating temperatures and electrical malfunctions.

Good with a correctly designed and operated system. Problems or changing well conditions reduce downhole pump reliability. Frequent downtime results from operational problems.

Good with proper throat and nose sizing for the operating conditions. Must avoid operating in cavitation range of jet pump throat, related to pump intake pressure. More problems if pressures >4,000psig.

Excellent if compression system is properly designed and maintained.

Excellent if there is an adequate supply of ingestion gas and adequate low pressure storage volume for injection gas. System must be designed for the unstable gas flow rates.

Good if well production is stable.

Salvage Value

Excellent, easily moved and good market for used equipment.

Fair to poor. Easily moved and some current market for used equipment

Fair. Some trade in value. Poor open market values.

Fair market for triplex pumps, good value for wellsite system that crane can move easily.

Good. Easily moved. Some trade in value. Fair market for triplex pump.

Fair. Some market for good used compressors and some trade in value for mandrels and valves.


Fair. Some trade in value. Poor open market value.

System (total)

Straightforward and basic. procedures to design, install and operates following API specifications and recommended practices. Each well needs an individual system.

Simple to install and operate. Limited proven design, installation and operating specifications Each well needs an individual system.

Fairly simple to design but requires good rate data. System not forgiving. Requires excellent operating practices. Follow API recommended practices in design, testing and operation. Typically each well is an individual producer using a common electric system.

Simple manual or computer design, typically used. Free pump easily retrieved for servicing. Individual well unit very flexible but extra cost. Requires attention. Central plant more complex, usually results in test and treatment problems.

Computer programme typically used for design. Basic operating procedures needed for downhole pump and wellsite unit. Free pump easily retrieved for onsite repair or replacement. Downhole jet often requires trial and error to arrive at best/optimum jet.

An adequate volume, high pressure, dry non-corrosive and clean gas supply source is needed throughout the entire life. System approach needed. Low back-pressure beneficial. Good data needed for valve design and spacing. API specifications and design/operatin g recommended practices should be followed.


Individual well or system. Simple to design, install and operate. Requires adjusting and plunger maintenance.

Usage/ Outlook

Excellent. Used on about 85% of US artificial lift wells. The normal standard artificial lift method.

Limited to relatively shallow wells with low rates. Used on less than 0.5% of US lifted wells. Used primarily on gas well dewatering.

An excellent high rate artificial lift system. Best suited for <200oF and >1,000BFPD rates. Most often used on high water cut wells.

Often used as a default artificial lift system. Flexible operation, wide rate range suitable for relatively deep, high volume, high temperature deviated oil wells. Used on <2% of US lifted wells.

GOR try higher volume wells requiring flexible operation. System will tolerate wide depth ranges, high temperatures, corrosive fluids, high GOR and significant sand production. Used on <1% of US lifted wells. Sometimes used to test wells that will not flow offshore.

Good, flexible, high rate artificial lift system for wells with high bottom-hole pressures. Most like a flowing well. Used on about 10% of US lifted wells, mostly offshore.

Often used as a default artificial lift method in lieu of sucker rod pumps. Also a default for low bottom-hole pressure wells on continuous gas lift. Used on <1% of US lifted wells.

Essentially a low liquid rate, high GLR lift method. Can be used for extending flow life or improving efficiency. Ample gas volume and/or pressure needed for successful operation. Used on <1% of US lifted wells.

Table 10.M - Design Considerations and Overall Comparisons (Pg2)

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10.7.2. Operating Conditions Summary Consideration

Rod Pumping

Screw Pumping

ESP



Continuous Gas Lift


Plunger Lift

Casing size limits (restricts tubing size)

Problems only in high rate wells requiring large plunger pumps. Small casing size (4.5 and 5.5ins) may limit free gas separation.

Normally no problem for 4.5ins casing and larger but gas separation may be limited.

Casing size will limit use of large motor and pumps. Avoid 4.5ins casing. Reduced performance inside 5.5ins casing depending on depth and rate.

Larger casing required for parallel free or closed systems. Small casing (4.5 and 5.5ins) mat result in excessive friction losses and limits production rate.

Small casing size often limits producing rate owing to high (unacceptable) friction losses. Larger casing may be required if dual strings run.

The use of 4.5 and 5.5ins casing with 2ins nominal tubing normally limits rates to <1,000stb/d. For rates >5,000stb/d use >7ins casing and >3.5ins tubing needed.

Small casing (4.5 and 5.5ins) normally is not a problem for this relatively low volume lift.

Small casing suitable for this low volume lift. Annulus must have adequate gas storage volume.

Depth limits

Good, rods of structure may limit rate at depth. Effectively about 500stb/d at 7,500ft and 150stb/d at 15,000ft.

Poor, limited to relatively shallow depths, possibly 5,000ft.

Usually limited to motor HP or temperature. Practical depth about 10,000ft.

Excellent, limited by power fluid pressure (5,000psi) or HP. Low volume, high lift head pumps operating at depths to 17,000ft

Excellent, similar limits as reciprocating pump. Practical depth of 20,000ft.

Controlled by system injection pressure and fluid rates. Typically for 1,000stb/d with 2.5ins nominal tubing. 1,440psi lift system and lift system and 1,000 GLR, has an injection depth of about 10,000ft.

Usually limited by fallback, few wells >10,000ft.

Typically <10,000ft.

Intake Capability

Excellent, <25psig feasible provided adequate displacement and gas venting. Typically about 50 to 100psig.

Good, <100psi provided adequate displacement and gas venting.

Fair. if little free gas (i.e. >250psi pump intake pressure). Poor if must handle >5% free gas.

Fair but not as good as rod pumping. Intake pressure <100psig usually results in frequent pump repairs. Free gas reduces efficiency and service life.

Poor to fair, >350psig to 5,000ft with low GLR. Typical design targets 25% submergence.

Poor restricted by the gradient of the gas lifted fluid. Typically moderate rate is limited to about 100psi/1,000ft injected depth. Thus the backpressure on 10,000ft well may be >1,000psig.

Fair when used without chambers. PIP >250psi for 10,000ft well. Good when used with chamber. PIP of <250psi feasible at 10,000ft.

Good, bottomhole pressures <150psi at 10,000ft for low rate, high GLR wells.

Noise Level

Fair, moderately high for urban areas.

Good with the surface prime mover causing the only noise.

Excellent with low noise. Often preferred in urban areas if production rate is high.

Good low well noise. Wellsite power fluid units can be sound proofed.

Same as piston pump.

Low at well but noisy at compressor.

Same as continuous flow.

Low.

Obtrusiveness

Size and operation are drawbacks in populated and farming areas. Special low profile units are available.

Good low profile surface equipment.

Good low profile but requires transformer bank. Transformer may cause problems in urban areas.

Fair to good wellhead equipment has low profile. Requires surface treating and high pressure pumping equipment.


Good low profile but must provide for compressor. Safety precautions must be taken for high pressure gas lines..


Low.

Prime mover flexibility

Good, both engines or motors can be used easily. Motors are more reliable and flexible.

Good, both engines or motors can be used.

Fair, requires a good power source without spikes or interruptions. Higher voltages can reduce I2R losses

Excellent. Prime mover can be electric motor, gas or diesel fired engines or motors.


Good, engines, turbines or motors can be used for compression.


None normally required.

Surveillance

Excellent, can be easily analysed based on well test, fluid levels, etc. Analysis improved by use of dynamometers and computers.

Fair, analysis can be based on production and fluid levels only. Not possible to use dynamometers and pump-off cards.

Fair based on electrical checks but special equipment needed otherwise.

Good to fair. Downhole pump performance can be analysed from surface power fluid rate and pressure, speed and producing rate. Bottom-hole pressure obtained with free pumps.


Good to excellent. Can be analysed easily. Bottomhole pressure and production log surveys easily obtained. Optimisation and computer control being tried.

Fair but complicated by standing valve and fallback.

Good but depends on good well test and pressure charts.

Table 10.N - Operating Conditions Summary

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Rod Pumping

Screw Pumping

ESP



Continuous Gas Lift


Plunger Lift

Testing

Good, Well testing is simple with few problems using standard available equipment and procedures.

Good, same as rod pumping.

Good, Well testing is simple with few problems. High water cut and high rate wells may require a free water knock-out.

Fair. Well testing with standard individual well units presents few problems. Well testing with a central system is more complex requiring accurate power fluid measurement.

Same as piston pump. Three stage production tests can be conducted by adjusting production step rates. A pressure recorder must be used to monitor intake pressures.

Fair. Well testing complicated by injection gas volume/rate. Formation GLR obtained by subtracting injected gas from total produced gas. Gas measurement errors are common.

Poor. Well testing complicated by injection gas volume/rate.. Measurement of both input and outflow gas is a problem. Intermittent flow can cause operating problems with separators.

Well testing is simple with few problems.

Time cycle and pump-off controller’s application

Excellent if well can be pumpedoff.

Good. Avoid shutdown in high viscosity/sand producers.

Poor. Soft start and improved seals and protectors recommended.

Poor, is possible but not normally used. Usually controlled only by displacement checks. Pumpoff control not developed.

Poor. Does not appear applicable owing to intake pressure requirement higher than pump-off.

Not applicable.

Poor. Cycle must be periodically adjusted. Labour intensive

Not applicable.

Table 10.O - Operating Conditions Summary (Pg2)

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10.7.3. Artificial Lift Considerations Consideration

Rod Pumping

Screw Pumping

ESP



Continuous Gas Lift


Plunger Lift

Corrosion/ scale handling ability

Good to excellent. frequently for both corrosion and scale control.

Good. Batch treatment inhibitor used down annulus feasible.

Fair. Batch inhibition treatment only to intake unless shroud is used.

Good to excellent. Batch or continuous inhibition treatment can be circulated with power fluid for effective control.

Good to excellent. Inhibitor mixed with power fluid mixes with produced fluids at entry of jet pump throat. Batch treat down annulus is feasible.

Good. Inhibitor in the injection gas and/or batch inhibiting down tubing feasible. Steps must be taken to avoid corrosion in injection gas lines.


Fair. Normal production cycle must be interrupted to batch treat the well.

Crooked/ deviated holes

Fair, increased load and wear problems. High angle deviated holes (>70o) and horizontal wells are being produced. Some success in pumping 15o/100ft using rod guides.

Poor to fair. Increased load and wear problems. Currently very few known installations.

Good. Few problems. Limited experience in horizontal wells. Requires long radius wellbore bends to get through.

Excellent if tubing can be run in the well. Pump will normally pass through the tubing. Free pump retrieved without pulling tubing. Feasible operation in horizontal wells.

Excellent, short pump can pass through doglegs up to 24o/100ft in 2ins nominal tubing. Same condition as hydraulic piston pump.

Excellent. Few wireline problems up to 70o deviation for wireline retrievable valves.


Excellent.

Dual application

Fair. Parallel 2x2ins low rate dual feasible inside 7ins casing. Dual inside 5ins casing currently not in favour. Gas is a problem for lower zone. Increased mechanical problems.

No known installations.

No known installations. Larger casing would be needed. Possible running and pulling problems.

Fair. Three string nonvented applications have been achieved with complete isolation of production and power fluid from each zone. Limited to low GLRs and moderate rates.

Same as piston pump except it can possibly handle higher GLRs but at reduced efficiency.

Fair. Dual gas lift is common but good operating of dual lift is complicated and inefficient resulting in reduced rates. Parallel 2x2ins nominal tubing inside 7ins casing and 3x3ins tubing inside 95/8ins casing feasible.


No none installations.

Gas handling ability

Good if can vent and use natural gas anchor with properly designed pump. Poor if must pump >50% free gas.

Poor if it must pump any free gas..

Poor for free gas >5% through pump. Rotary gas separators helpful if solids not produced.

Good to fair. Concentric fixed pump or parallel free permits gas venting with suitable downhole gas separator below pump intake. Casing free pump limited to low GLRs.

Similar to piston pump. Free gas reduces efficiency but helps lift. Vent free gas if possible. Use a gas anchor.

Excellent. Produced gas reduces need for injection gas.

Same as continuous flow

Excellent.

Offshore application

Poor. Must design for unit size, weight and pulling unit space. Most wells are deviated and typically produce sand.

Poor. May have some special application offshore, however a pulling unit is needed.

Good. Must provide electrical power and service pulling unit.

Fair. Feasible operation in highly deviated wells. Requires deck space for treatment tanks and pumps. Water power fluid can be used. Power oil a fire and safety problem.

Good. Produced water or seawater may be used as a power fluid with wellsite type system or power fluid separation before production treating system.

Excellent and is the most common method if adequate injection gas available.

Poor in wells needing sand control. Use of standing valves risky. Heading causes operating problems.

Excellent for correct application.

Paraffin handling capacity

Fair to good. Hot water/oil treating and/or use of scrapers possible but they increase operating problems and costs.

Fair. Tubing may require treatment. Rod scrapers not used. Possible to unseat pump and circulate hot fluids.

Fair to good. Hot water/oil treatments, mechanical cutting, batch inhibition possible.

Good to excellent. Circulate heat to downhole pump to minimise build-up. Mechanical cutting and inhibition possible. Soluble plugs available. Free pumps can be surfaced on a schedule.


Good mechanical cutting sometimes required. Injection gas may aggravate existing problem.


Excellent as it cuts paraffin and removes small deposits.

Table 10.P - Artificial Lift Considerations (Pg1)

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Consideration

Rod Pumping

Screw Pumping

Slim-hole completions (27/8ins production casing string)

Feasible for low rates <100stb/d and low GOR <250. Typically are used with 1.5ins nominal tubing.

Feasible if low rates, low GORs and shallow depths but no known installations.

Solids/sand handling ability

Poor to fair for low viscosity <10cP production. Improved performance for high viscosity >200cP cases. May be able to handle up to 0.1% sand with special pumps.

Temperature limitation

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ESP

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Continuous Gas Lift


Plunger Lift

No known installations.

Possible but may have high friction losses or gas problems. Suitable for low rates and low GLRs.


Feasible but can be troublesome and inefficient.


Good. Similar to casing lift but must have adequate formation gas.

Excellent up to 50% sand with high viscosity >200cP crude. Decreases to <10% sand for water producers.

Poor. Requires <200ppm solids. Improved wear resistant materials available at premium cost.

Poor. Requires <10ppm solids power fluid for good run life. Also produced fluids must have low solids <200ppm of 15µm particles for reasonable life. Use fresh water injection for salt build-up formations.

Fair to good. Jet pumps are operating with 3% sand in produced fluids. Power fluid to jet pump can tolerate 200ppm of 25µm particle size. Fresh water treatment for salt formations.

Excellent. Limit is inflow and surface problems. Typical limit is 0.1% sand for inflow and outflow problems.

Fair but standing valve may cause problems. Same as continuous flow.

Sand can stick plunger, however it wipes tubing clean.

Excellent and currently used in thermal operations. 550oF.

Fair but limited by stator elastomer. At present normally below 250oF.

Limited to about <250oF for standard and <325oF with special motors and cables.

Excellent. Standard materials up to 300oF+ and to 500oF+ feasible with special materials.

Excellent and possible to operate to 500oF with special materials.

Excellent. Typically a maximum of about 350oF. Need to know temperatures to design bellows charged valves.


Excellent.

High viscosity fluid handling capability

Good for <200cP fluids and low rates 400stb/d. Rod fall problems for high rates. Higher rates may required dilutent to lower viscosity.

Excellent for high viscosity fluids with no stator/rotor problems.

Fair, limited to about 200cP. Increases HP and reduces head. Potential solution is to use ‘core flow’ with 20% water.

Good in >8o API production with <500cP possible. Power fluid can be used to dilute low gravity production.

Good to excellent. Production with up to 800cP possible. Power oil of oil >24o API and ,50cP viscosity or water power fluid reduces friction losses.

Fair. Few problems for >16 o API. or below 20cP viscosity. Excellent for high water cut lift even with high viscosity oil.

Same as continuous flow

Normally not applicable.

High volume lift capacity

Fair but restricted to shallow depths using large plungers . max. rate about 4,000stb/d from 1,000ft and 1,000stb/d from 5,000ft.

Poor. Restricted to relatively small rates. Possibly 2,000stb/d from 2,000ft and 200stb/d from 5,000ft.

Excellent. limited by needed HP and can be restricted by casing size. In 5.5ins casing can produce 4,000stb/d from 4,000ft with 240 HP. Tandem motors can be used but will increase costs.

Good. Limited by tubular and HP. Typically 3,000stb/d from 4,000ft and 1,000stb/d from 10,000ft with 3,500psi system.

Excellent. Up to 15,000stb/d with adequate flowing bottomhole pressure, tubular size and HP.

Excellent. Restricted by tubing size and injection gas rate and depth. Depending on reservoir pressure and PI with 4ins nominal tubing, rates of 5,000stb/d from 10,000ft feasible with 1,440psi injection gas and GLR of 1,000.

Poor. Limited by cycle volume and number of possible injection cycles. Typically about 200stb/d from 10,000ft with <250psi pump intake pressure.

Poor. Limited by number of cycles. Possibly 200stb/d from 10,000ft.

Low volume lift capabilities

Excellent. Most commonly used method for wells producing <100stb/d.

Excellent for <100stb/d shallow wells that do not pump-off.

Generally poor. Lower efficiency and high operating costs for <400stb/d.

Fair. Not as good as rod pumping. Typically 100 to 300stb/d from 4,000 to 10,000ft, >75stb/d from 12,000ft possible.

Fair, >200stb/d from 4,000ft.

Fair. Limited by heading and slippage. Avoid unstable flow range. Typically lower limit is 200stb/d for 2ins tubing without heading, 400stb/d for 2.5ins and 700stb/d for 3.5ins tubing.

Good. Limited by efficiency and economic limit. Typically 0.5 to 4stb/cycle with up to 48 cycles/d

Excellent for low flow rates of 1 to 2stb/d with high GLRs.

Table 10.Q - Artificial Lift Considerations (Pg2)

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11.

USE OF UNDERBALANCE COMPLETION FLUIDS

11.1.

POLICY The purpose of this section is to provide the basic criteria when ‘non-kill weight packer fluids’ can be used in completion design. The use of non-kill weight packer fluid has been thoroughly evaluated and is permitted for the wells which have pressure gradients above 1.30kg/Lt/10m, i.e. high pressure and high temperature (HP/HT) wells. This policy does not refer to gradients below 1.30kg/Lt/10m where it is still considered good practice to use overbalance completion fluids.

11.2.

BARRIER PRINCIPLES Eni-Agip Division and Affiliates has determined that a packer fluid, regardless of the density, cannot be considered as a barrier. The main reasons are: •

•

•

11.3.

The integrity of the annulus, with regard to double barrier protection is mechanically obtained by means of the wellhead, the tubulars (tubing and casing) and packer system and, therefore, does not require the presence of an overbalance fluid. A hydrostatic overbalance fluid can only be considered a barrier on a long term basis if it is fully maintained, however tubing leaks and deterioration of the fluid cannot be guaranteed. This being the case, it should not be classified as a barrier. Over and above this, some completion types such as High Rate liners using a liner PBR may be some considerable distance from the formation, therefore is not a practical barrier.

APPLICATION The use of non-kill weight packer fluid will be considered in the following situations: • • •

When a brine with a gradient lower than the formation gradient has already been used as completion fluid, i.e. through tubing perforation after packer setting. When it is necessary to replace a completion fluid containing solids in suspension, i.e. high density oil mud. The re-use of the completion fluid is envisaged when it is opportune or cost effective.

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RISK ASSESSMENT

11.4.1. Well Testing For exploration wells, prior to commencing a well test using non-kill weight packer fluid, a risk analysis evaluation (HAZOP) must be carried out by the District Drilling & Completion Engineering Department, in order to identify and evaluate the operative risks associated with downhole equipment functionality. 11.4.2. Completions Similar to above, a risk assessment should be carried out to ensure, if an underbalance completion fluid is to be used, that the completion design will keep the formation pressure off the production casing. However, as contingency against a tubing/packer envelope leak, the casing design must be able to withstand full well pressure in conjunction with the completion fluid hydrostatic pressure at respective depth. The worst possible case being immediately above the packer.

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APPENDIX A - REPORT FORMS To enable the contents of this completion manual and other operating procedures manuals to be improved, it is essential that ENI - Agip Division and Affiliates obtain feed-back from the field. To this end a feed-back reporting system is in use which satisfies this requirement. Feed-back reports for drilling, completion, workover and well testing operations are available and must be filled in and returned to head office for distribution to the relevant responsible departments as soon as possible as per instructions. The forms relevant to completion operations are: •

ARPO 01

Initial Activity Report

•

ARPO 02

Daily Report

•

ARPO 06

Waste Disposal Management Report

•

ARPO 07

Perforating Report

•

ARPO 08

Gravel Pack Report

•

ARPO 09

Matrix Stimulation/Hydraulic fracturing Report

•

ARPO 11

Wireline Report

•

ARPO 12

Pressure/Temperature Survey Report

•

ARPO 13

Well Problem Report

•

ARPO 20

Well Situation Report

Behind each report form are instructions on how to fill in the forms. As the first section is generic to all the forms it is only shown in ARPO 01 instructions.

ARPO

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A.1.

277 OF 295

0

INITIAL ACTIVITY REPORT (ARPO 01)

District/Affiliate Company DATE:

INITIAL ACTIVITY REPORT ARPO 01

Permit/Concession N°

FIELD NAME Cost center

Well Code

General Data On shore

WELL NAME

Depth Above S.L .

Off shore

Joint venture

Ground Level[m]

AGIP:

%

%

Latitude:

Water Depth [m]

%

%

Longitude

Rotary Table Elev.[m]

%

%

Reference

First Flange[m]

Rig Name

Top housing [m]

Type of Operation

Reference Rig

Rig Type Contractor

Ref. Rig RKB - 1st Flange

Program TD (Measured)

[m]

Program TD (Vertical)

[m]

Cellar Pit

Rig Heading [°]

Rig Pump

Depth [m]

Offset FROM the proposed location

Manufacturer

Distance [m]

Length [m]

Type

Direction [°]

Width [m]:

Liner avaible [in] Major Contractors

Type of Service

Company

Contract N°

Type of Service

Company

Contract N°

Mud Logging D. & C. Fluids Cementation Waste treatment Operating Time

Jack-up leg Penetration

Supply Vessel for Positioning

Moving

[gg:hh]

Leg

Air gap

Penetration

Positioning

[hh:min]

N°

[m]

[m]

Anchorage

[hh:min]

Rig-up

[hh:min]

Delay

[hh:min]

Lost-time Accidents

[hh:min]

N°

Name

Horse

Bollard pull

Power

[t]

Rig Anchorage Anchor Bow N°

Angle

Mooring Line Weight

Type & Manufacturer

[t]

Piggy Back

Length Cable

Chain

[m]

[m]

Weight N°

[t]

Mooring Line Chain

Tension Operative

Cable

Length

Ø

Length

Ø

[m]

[mm]

[m]

[mm]

Tension

Time

[t]

[t]

[hh:min]

1 2 3 4 5 6 7 8 9 10 11 12 Note:

Total

[Tested]

Supervisor

Superintendent

ARPO

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A.2.

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0

DAILY REPORT (ARPO 02)

DAILY REPORT

WELL NAME

Drilling

FIELD NAME

District/Affiliate Company ARPO 02

DATE:

Cost center

Rig Name

RT Elevation

[m]

Well Code

Type of Rig

Ground Lelel / Water Depth

[m]

Report N°

Contractor

RT - 1st flange / Top Housing

[m]

Permit / Concession N°

Well

Last casing

BOP

Next Casing

Ø

Type

w.p. [psi]

of

M.D. (24:00)

[m]

Ø nom.[in]

Stack

T.V.D. (24:00)

[m]

Top [m]

Diverter

Total Drilled

[m]

Bottom [m]

Annular

Rotating Hrs

[hh:mm]

Top of Cmt [m]

Annular

R.O.P.

[m / h] [hh:mm]

Last Survey [°]

at m

Upper Rams

Progressive Rot. hrs

LOT - IFT [kg/l]

at m

Middle Rams

Back reaming Hrs

Middle Rams

Personnel

Reduce Pump Strockes Pressure 1

Pump N°

2

3

[hh:mm] Injured

Middle Rams

Agip

Agip

Liner [in]

Lower Rams

Rig

Rig

Strokes Press. [psi]

Last Test

Others Total

Other Total

Lithology Shows From (hr)

To (hr)

Op. Code OPERATION DESCRIPTION

Operation at 07:00 Mud type Density Viscosity P.V. Y.P. Gel 10"/10' Water Loss HP/HT Press. Temp. ClSalt pH/ES MBT Solid Oil/water Ratio. Sand pm/pom pf mf Daily Losses Progr. Losses

[kg/l] [s/l] [cP] [g/100cm2] / [cc/30"] [cc/30"] [kg/cm2] [°C] [g/l] [g/l] [kg/m3] [%] [%]

Bit Data Manuf. Type Serial No. IADC Diam. Nozzle/TFA From [m] To [m] Drilled [m] Rot. Hrs. R.P.M. W.O.B.[t] Flow Rate Pressure Ann. vel. Jet vel. HHP Bit HSI I [m 3] [m 3] B

N°

Run N°

N°

Run N°

Bottom Hole Assembly N° __________ Rot. hours Ø Description Part. L Progr.L Partial Progr.

Stock

Total Cost O G

D O

L R

I B

O G

D O

L R

Daily Progr.

Quantity

UM

Supervisor:

Supply vessel

ARPO

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A.3.

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0

WASTE DISPOSAL MANAGEMENT REPORT (ARPO 06)

WASTE DISPOSAL

WELL NAME

Management Report

FIELD NAME

District/Affiliate Company ARPO-06 Cost center

DATE: Report N°

Depth (m)

Mud Type

From [m]

Density (kg/l)

To [m]

Interval Drilled (m) 3 Drilled Volume [m ]

Phase size [in]

Cumulative volume [m ]

Cl- concentration (g/l ) 3

3

Usage

3

Phase /Period [m ]

Water consumption Fresh water

Recycled

Cumulative [m ] Total

Fresh water

Recycled

Total

Mixing Mud Others Total 3

3

Fresh water [m ]

Readings / Truck 3

Mud Volume [m ]

Phase

Cumulative

Recycled [m ] Service

Mixed

Company

Contract N°

Mud Company

Lost

Waste Disposal

Dumped

Transportation

Transported IN Trans orted OUT Waste Disposal Water base cuttings

Period

Oil base cuttings

[t] [t]

Dried Water base cuttings

[t]

Dried oil base cuttings

[t]

Water base mud

[t]

Oil base mud transported IN

[t]

Oil base mud transported OUT

[t]

Drill potable water

[t]

Dehidrated water base mud

[t]

Dehidrated oil base mud

[t]

Sewage water

[t]

Transported Brine

[t]

Cumulative

Remarks

Remarks

Supervisor

Superintendent

ARPO

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A.3.

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0

PERFORATING REPORT (ARPO 07)

PERFORATING REPORT

District/Affiliate Company

Onshore

FIELD NAME

ARPO-07

DATE: Well location

WELL NAME

Cost center

Formation name:

Pool:

Lithology

Offshore [m]

Total Depth

st

Final Workover Report [date]

st

Workover Rig RKB - 1 Flange

Vertical

T.V.D.

Deviated

Max. inclination

Horizontal

at Size [Ø]

Well

Final Completion Report [date]

Rotary Table Measurement [m] Drilling Rig RKB - 1 Flange

M.D.

Well Type

Situation

Reference Logs:

[°]

Workover Rig RKB - Sea Level

[m]

Workover Rig RKB - Sea Bottom

Steel

Thickness

Grade

[lb/ft]

Measured Depth Top [m]

Bottom [m]

Recorded on: Vertical Depth Top [m]

Bottom [m]

Cement Top M.D. [m]

T.V.D. [m]

Liner Casing Casing Tubing

Service Company

Packer Tubing shoe Perforation System Wireline

Overbalance

Completion fluid

Density

[kg/l]

TCP

Underbalance

Fluid in front of Perforation

Density

[kg/l]

Thru Tubing

Differential Pressure [kg/cm ]

Data

2

Gun

Gun

Gun

Charge

Type

Specific.

Ø

Type

Fluid Losses after Perforation S.P.F


Bottom [m]

[m3] Vertical Depth Top [m]

Bottom [m]

Note:

Supervisor

Superintendent

Pool

Remarks

ARPO

IDENTIFICATION CODE

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A.4.

281 OF 295

GRAVEL PACK REPORT (ARPO 08)

Cannot Load File form supplied Eni-Agip Excel

0

ARPO

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0

MATRIX STIMULATION/HYDRAULIC FRACTURE REPORT (APRO 09)

MATRIX STIMULATION HYDRAULIC FRACTURING

WELL NAME FIELD NAME

District/Affiliate Company ARPO - 09

DATE: Well Location Onshore

Cost center

General Data

Interval to be Treated Tot. net perf.:

M.D. [m]

Open hole

Offshore

T.V.D. [m]

Perfor. interval

Well Type Vertical

Open hole Ø Prod. casing / liner Ø

Slotted liner From [m]

Pool:

Deviated Horizontal

Shoe M.D. [m] Top liner [m]

To [m]

Lithology:

Treatment Type Matrix stimulation Acid Solvent Other Hydraulic Fracturing

Treatment Data Service Company

Density [Kg/l] 2 Gradient [Kg/cm /10 m.]

HHP avaible

Type

Initial Shut-in pressure [psi]

Wellhead type

Completion Data Bottom hole gauge [Y / N]

Fracturing gradient [calculated]

Annulus pressure [psi]

Packer type

Fracturing gradient [tested]

Pressure test [psi]

Packer fluid

Porosity %

Water base

SBHT [°C] 2 SBHP [kg/cm ]

Oil base

Formation name:

Reservoir Parameters Reservoir fluid

Foam

Max. injection rate [bpm]

Density

at m

Max. injection pressure [psi]

Fluid in well at operation beginning

at m

Pumping time [min]

Other

Pumping time [min]

Acid Fracturing

String O.D. [in]

Equipment

String capacity [l]

Acid

Main Frac Treatment Proppant type:

Gelled acid

API Mesh Size

Ø

Acid + Gel

Amount of Propant [t] 3 Total Frac Fluid Vol. [m ]

Stimulation vessel / Other equipment

Other

Coiled Tubing [Y / N]

Packer - Top perforation Volume [l]

Operation Description Fluid Ref.

Fluid Schedule Fluid Composition

Fluid Type

Density [kg/l]

1 2 3 4 5 6 7 8 9 10 N° Fluid Ref.

Injected Circulated

A.5.

282 OF 295

Starting

Pumping

Time

Rate [bbl/1']

Volume

Progr. Volume

3

[m ]

3

[m ]

Pumping Parameter Progr.Vol. Proppant Initial Entering in Formation

Final

Injection

Casing

Concentr.

Press.

Press.

Index

Press.

[lb/gal]

[psi]

[psi]

[bbl/day/psi]

[psi]

Notes / Remarks: Supervisor

Superintendent

Notes

Mixed Volume [m3 ]

ARPO

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A.6.

283 OF 295

0

WIRELINE REPORT (ARPO 11)

WIRE LINE REPORT

WELL NAME FIELD NAME

District/Affiliate Company ARPO - 11

DATE:

SINGLE COMPLETION

Cost center

SHORT STRING

SELECTIVE

DUAL COMPLETION

Well Code

LONG STRING General Data

RKB Elevation @ m.

Flanges

Base Flange

Tbg Spool

Top Flange Ø

Psi

Tubing Size OD

Weight [lb/ft]

@ m.

Flowing Flange Ø

Psi

Tubing Size OD

Weight [lb/ft]

@ m.

Kill Line Flange Ø

Psi

@ m. @ m.

BPV Type

Ø

Tubing Shoe Ø Packer data

@ m. Minimum I.D. String Previous Bottom Hole

@ m.

Request Operation

THP

Wellhead Pressure Check [Kg/cm2] CHP

[Kg/cm 2]

Annulus Annulus

/ /

P P

[Kg/cm 2] [Kg/cm 2]

Annulus

/

P

[Kg/cm 2]

POOL Perforated Zones

Open Hole

From [m]

To [m]

Note

Operation Description

Situation After the Job NO TOOLS IN HOLE TSV Note

SCSSV BPV

PLUG

Actual Bottom Hole: OTHER TOOLS

Max Size Run in Hole Ø Supervisor Superintendent

@m

ARPO

IDENTIFICATION CODE

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A.7.

284 OF 295

0

PRESSURE/TEMPERATURE SURVEY REPORT (ARPO 12)

Cannot Load File form supplied Eni-Agip Excel

ARPO

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A.8.

0

WELL PROBLEM REPORT (ARPO 13)

WELL PROBLEM REPORT

District/Affiliate Company

DATE: Problem Code Well

Ø

Situation

ARPO -13

WELL NAME Cost center Start date

Bottom [m]

End date


FIELD NAME

Top [m]

Vertical Depth

Bottom [m]

Top [m]

KOP

Bottom [m]

Open hole

Mud in hole

[m]

Max inclination [°]

Type

@m

Last casing

Dens.[kg/l]:

DROP OFF [m]

Well problem Description

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Supervisor

Supervisor

Supervisor

Remarks at District level:

Superintendent Lost Time Remarks at HQ level

285 OF 295

hh:mm Loss value [in currency] Pag. Of

ARPO

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A.9.

286 OF 295

0

WELL SITUATION REPORT (ARPO 20)

WELL SITUATION

FIELD NAME

(COMPLETION TALLY)

WELL NAME

District/Affiliate Company ARPO 20 / E

DATE:

SINGLE COMPLETION Joint n°

m

Progr. m

DUAL COMPLETION Note

Joint n°

Cost center

SHORT STRING

m

Progr. m

Note

Joint n°

LONG STRING m

Supervisor

Remarks:

Superintendent pag.:

of:

Progr. m

Note

ARPO

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APPENDIX B - NOMENCLATURE FOR TUBING CALCULATIONS Ai Ao Ap As D d Dpb E F Fa * Fa Fa tp * Fa tp Ff * Ff I Ff II Ff Ff tp * Ff tp Fp Fso I L n

= = = = = = = = = = = = = = = = = = = = = = = =

Pi /pi Po /po R r t Tfinal Tinitial w ws wfi wfo α γfi γfo ∆Fa ∆Ff ∆L ∆L1 ∆L2 ∆L3 ∆L4

= = = = = = = = = = = = = = = = = = = = =

Area inside tubing Area outside tubing Packer-bore area Resistant tubing area (Ao - Ai) External diameter of tubing Internal diameter of tubing Packer-bore diameter 7 Young’s module (3⋅10 psi for steel) Generic force applied to the tubing end Piston force at the packer depth Piston force above the packer with anchored tubing Piston force at well head conditions Piston force at well head conditions with anchored tubing Fictitious force Fictitious force above the packer with anchored tubing Fictitious force due to the effect of internal pressure Fictitious force due to the effect of external pressure Fictitious force at well head conditions Fictitious force at well head conditions with anchored tubing Tubing-packer force Slack-off force Moment of inertia of the resistant tubing section Tubing length Distance between the lower end of the tubing and the neutral point Pressure inside the tubing at packer depth / well head Pressure outside the tubing at packer depth / well head Ratio between the external and internal diameters of the tubing Tubing-casing radial distance (Douter casing -D)/2 Tubing wall thickness Final temperature of tubing Initial temperature of tubing Linear weight of the tubing immersed in fluid Linear weight of the tubing in air Linear weight of fluid inside the tubing Linear weight of fluid outside the tubing -6 Coefficient of thermal expansion (6.9⋅ 10 in/in/°F for steel) Specific gravity of fluid inside the tubing Specific gravity of fluid outside the tubing Variation in the piston force Variation in the fictitious force Generic variation in the tubing length Variation in length due to Hooke’s Law Variation in length due to buckling Variation in length due to ballooning Variation in length due to thermal effects

ARPO

IDENTIFICATION CODE

PAGE



∆Lp ∆Lf ∆lso ∆ltot ∆Pi ∆pim ∆pom ∆TM ν σa σb σeq σi σo σsn Yp

= = = = = = = = = = = = = = = =

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0

Total variation in length prevented by the packer Variation in length generated by fictitious force Variation in length generated by slack-off force Total variation in length of the tubing (= - ∆Lp) Variation in pressure inside the tubing Average variation in pressure inside the tubing Average variation in pressure outside the tubing Average variation in tubing temperature Poisson’s coefficient (0.3 for steel) Axial stress in the tubing section Axial stress in the tubing section due to buckling Equivalent axial stress Equivalent axial stress on the inner wall of the tubing Equivalent axial stress on the outer wall of the tubing Material yield axial stress σsn

ARPO

IDENTIFICATION CODE

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APPENDIX C - ABBREVIATIONS API BHA BHP BHT BOP BPD BPM BPV BSW BUR C/L CBL CCL CET CGR CRA C/T DC DE DHSV D&CM DP DST E/L ECD ECP EMW ESD ESP ETA FBHP FBHT FTHP FTHT GLR GOC GOR GP GPM GPS GR HAZOP HP/HT IADC ID

289 OF 295

American Petroleum Institute Bottom Hole Assembly Bottom Hole Pressure Bottom hole temperature Blow Out Preventer Barrel Per Day Barrels Per Minute Back Pressure Valve Base Sediment & Water Build Up Rate Control Line Cement Bond Log Casing Collar Locator Cement Evaluation Tool Condensate Gas Ratio Corrosion Resistant Alloy Coiled Tubing Drill Collar Diatomaceous Earth Down Hole Safety Valve Drilling & Completion Manager Drill Pipe Drill Stem Test Electric Line Equivalent Circulation Density External Casing Packer Equivalent Mud Weight Electric Shut-Down System Electrical Submersible Pump Expected Arrival Time Flowing Bottom Hole Pressure Flowing Bottom Hole Temperature Flowing Tubing Head Pressure Flowing Tubing Head Temperature Gas Liquid Ratio Gas Oil Contact Gas Oil Ratio Gravel Pack Gallon (US) per Minute Global Positioning System Gamma Ray Hazard and Operability High Pressure - High Temperature International Drilling Contractor Inside Diameter

0

ARPO

IDENTIFICATION CODE

PAGE



IPR JAM KOP LAT LCM LMRP LOT LWD MAASP MD MLH MLS MMS MODU MPI MSL MSS MWD NACE NDT NSG NTU OBM OD OIM ORP OWC P&A PBR PDC PDM PGB PI PLT POB PPB ppg ppm PVT Q Q/AQ RFT RKB ROE ROP ROU ROV

290 OF 295

Inflow Performance Relationship Joint Make-up Torque Analyser Kick Off Point Lowest Astronomical Tide Lost Circulation Materials Low Marine Riser Package Leak Off Test Log While Drilling Max Allowable Annular Surface Pressure Measured Depth Mud Line Hanger Mud Line Suspension Magnetic Multi Shot Mobile Offshore Drilling Unit Magnetic Particle Inspection Mean Sea Level Magnetic Single Shot Measurement While Drilling National Association of Corrosion Engineers Non Destructive Test North Seeking Gyro Nephelometric Turbidity Unit Oil Base Mud Outside Diameter Offshore Installation Manager Origin Reference Point Oil Water Contact Plugged & Abandoned Polished Bore Receptacle Polycrystalline Diamond Cutter Positive Displacement Motor Permanent Guide Base Productivity Index Production Logging Tool Personnel On Board Pounds per Barrel Pounds per Gallon Part Per Million Pressure Volume Temperature Flow Rate Quality Assurance, Quality Control Repeat Formation Test Rotary Kelly Bushing Radius of Exposure Rate Of Penetration Radios Of Uncertainty Remote Operated Vehicle

0

ARPO

IDENTIFICATION CODE

PAGE



RPM RT S/N SAFE SBHP SBHT SCC SCSSV SDE SF SG SICP SIDPP SPM SSC SSD SSSV STHP STHT TCP TD TOC TOL TRSV TVD UHF VBR VDL VHF VSP W/L WBM WC WHP WHSIP WOB WOC WOW WP YP

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Revolutions Per Minute Rotary Table Serial Number Slapper Activated Firing Equipment Static Bottom Hole Pressure Static Bottom Hole Temperature Stress Corrosion Cracking Surface Controlled Subsurface Safety Valve Senior Drilling Engineer Safety Factor Specific Gravity Shut-in Casing Pressure Shut-in Drill Pipe Pressure Stroke per Minute Sulfide Stress Cracking Sliding Sleeve Door Valve Sub Surface Safety Valve Static Tubing Head Pressure Static Tubing Head Temperature Tubing Conveyed Perforations Total Depth Top of Cement Top of Liner Tubing Retrievable Safety Valve True Vertical Depth Ultra High Frequency Variable Bore Rams (BOP) Variable Density Log Very High Frequency Velocity Seismic Profile Wire Line Water Base Mud Water Cut Well Head Pressure Well Head Shut-in Pressure Weight On Bit Wait On Cement Wait On Weather Working Pressure Yield Point

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APPENDIX D - BIBLIOGRAPHY Document:

STAP Number

Drilling Design Manual

STAP P-1-M-6100

Connection Procedures Manuals.

STAP M-1-M 5006

Other References: Ansari, A ‘ A Comprehensive Mechanistic Model For Multiphase Flow In Wells’, MS Thesis, The University Of Tulsa (1988) API BUL 5C3 Sixth Edition: ‘Formulas and Calculations for Casing Tubing Drill Pipe, and Line Pipe Properties’, October 1, 1994. API RP 14E ‘Recommended Practices For Design And Installation Of Offshore Production rd Platform Piping Systems, 3 edition (Dec 1981) API RP 14E Fourth Edition: ‘Recommended Practice for Design and Installation of Offshore Production Platform Piping System’, April 15, 1984. Arthur Lubinsky: ‘Helical Buckling of Tubing Sealed in Packers’, 36th Annual Fall Meeting of SPE, Dallas, October 8-11, 1961. Aziz, K, Covier, GW and Fogarasi, M : ‘ Pressure drop in wells producing oil and gas’ (July Sept 1972), 38-48 Beggs, H D and Brill, J P : ‘ A study of two-phase flow in inclined pipes’ (May 1973), 607617 Blount, E M, Jones, L G and Glaze, O H : ‘Use of short term multirate flow tests to predict performance of wells having turbulence’ (1976) Brown, K E : The Technology Of Artificial Lift Methods, Vols 1 And 4, Ponwell Publishing Company, Tulsa, OK, 1977 Bruist, E HY : ‘ Better performance of Gulf Coast wells’( 1974) D. J. Hammerlind: ‘Basic Fluid and Pressure Forces on Oilwell Tubulars’, 53th annual Fall Technical Conference and Exhibition, Houston, October 1-4, 1978. D. J. Hammerlind: ‘Movement, Forces and Stresses Associated With Combination Tubing Strings Sealed in Packers’, Journal of Petroleum Technology, February, 1977. Duns, H JR and Ros, N C J : ‘ Vertical flow of gas and liquid mixtures in wells’ (1963), 451 Earlougher, R C JR and Kersch K M : ‘ Analysis of short-time transient test data by typecurve matching’ (July 1974) 793 Eickmeier, J R : ‘ How To Accurately Predict Future Well Productivities’ ( May 1968) 99-106 Fetkovich, M J : ‘ The Isochronal Testing Oil Wells’ (1973) Forcheimer, P ;P ‘ Wasserbewegung Durch Boden’ (1901) 45, 1781-1788 (in german) Gilbert, W.E: ‘Flowing and Gas-Lift Well Performance’ API Drill and Prod Pract (1954), 126 Golan, M and Whiston, C H: Well Performance, International Human Resource Development Corporation, Boston, NY (1986)

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Gray, H E : ‘ Vertical Flow Correlation-Gas Wells’ API Man 14BM; API 14B, SSCSSV Sizing Computer Program, 38-40 H. D. Beggs: ‘Production Optimisation Using NODAL Analysis’, OGCI, Tulsa, 1991. Hagedoorn, A R and Brown, K E: ‘ Experimental study of pressure gradients occurring during continuous two-phase flow in small diameter vertical conduits’ ( April 1965) 475-484 Hagedorn and Brown (1967) Horner, D R : ‘ Pressure build up in wells’ (1951) Hurst, W : ‘ Establishment of skin effect and its impediment to fluid flow into a wellbore’ (Oct 1953) King, G E, Anderson, A R and Bingham, M D ‘ A field study of underbalance pressure necessary to obtain clean perforations using tubing-conveyed perforating’ ( June 1986) 662 Lea, J F JR and Tighe, R E : ‘ Gas Well Operations With Liquid Production’ ( 1983) Milner, E E and Warren D A JR : ‘ Drill stem test analysis utilising McKinley system of after flow dominated pressure build up’ (Oct. 1972) Orkiszewski, J : ‘ Predicting Two-Phase Pressure Drops In Vertical Pipes’ (June 1967), 829838 Ramey, H J JR : ‘ Short-Time Well Test Data Interpretation In The Presence Of Skin Effect And Wellbore Storage, (Jan 1970) 97 Rawlins, E L and Schellhardt, M A : ‘ Back-Pressure Data On Natural Gas Wells And Their Application To Production Practices’ US Bureau Of Mines, (1936) Reinicke, K M, Remer, R J and Hueni, G : ‘ Comparison Of Measured And Predicted Pressure Drops In Tubing For High-Water-Cut Gas Wells’ (Aug 1987) 165-177 Saucier, R J : ‘ Gravel pack design consideration’ (Feb 1974) Standing, M B : ‘ Concerning The Calculation Of Inflow Performance Of Wells Producing From Solution Gas Drive Reservoirs’ (Sept 1971) 1141-1142 Texas Railroad Commission Rule 36 Turner, R G, Hubard, M G and Duckler, A E : ‘ Analysis And Predictions Of Minimum Flow Rate For The Continuous Removal Of Liquid From Gas Wells’ (Nov 1969) Van Everdingen, F : ‘ The Skin Effect And Its Influence On The Productive Capacity Of A Well’ (Oct 1953) Van Poollen, H K : ‘ Radius-Of-Drainage And Stabilisation Time Equations’ (Sept 1964) Vol 62. No 37 Vogel, J V : ‘ Inflow Performance Relationships For Solution Gas Drive Wells’, (Jan 1968) 83-93

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APPENDIX E - TUBING MOVEMENT/STRESS COMPUTER PROGRAMMES E.1.

‘VERTUBING’ PROGRAMME The need to fast computing to carry out tubing movement/stress calculations led AGIP to produce the ‘Vertubing’ programme in 1989. This application was based on a previous version designed by a company named ‘Tubmov’ which was run on Hewlett Packard 41CV computers. The ‘Vertubing’ programme provided a calculation tool which significantly reduced times for engineers involved in string calculations. The programme also enabled users to find an optimal solution by means of the iterative process using a number of approximations and producing results which were more reliable. The programme is supported by VAX/VMS computer systems and is currently available at Head Office and in the Districts on the Company computer network. The application carries out all functions for tubing control in vertical or deviated wells, with a string and a high number of packer’s as well (multiple zone completions) and takes into account the fact that packer setting can be mechanical or hydraulic. It is also possible to check stress tubing’s with varying diameters (tapered string) and to consider materials with anisotropic characteristics. It is not, however, possible to take into account the reduction in the performance of some CRA type steels, caused by temperature increases. The programme does not incorporate a library or collection of data on commonly used tubing material, which would enable users to design the string starting from an existing material. The programme’s architecture defines a rigid sequence for data entry, which results in extremely accurate results. The application does not enable the user to independently assess dynamic situations such as with production or injection operations. It is necessary to calculate load losses during the relative operation and obtain the resulting fictitious hydrostatic gradient which then lets the user obtain the correct pressures for the various string sections. ‘Vertubing’ produces the results as numerical files, without any graphic display. The programme is generally considered to be reliable because the results of three years use have consistently matched actual well applications.

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‘WELLCAT’ PROGRAMME Eni-Agip Division and Affiliates recently acquired Enertech’s (1994) ‘Wellcat’ programme which is an application integrating the most specialised software, ranging from drilling, to completion and other various well operations. The brief description below only describes the parts of the application concerning tubing. The need to use an in-house company programme which was more complex compared to ‘Vertubing’, is due to this application’s limitations in terms of obtaining the trend of temperatures the string is subject to during various well operations, and the inability to analyse dual completions. As ‘Vertubing’ had to be integrated with software in ENI-Agip Division and Affiliates expert system (Welcome) it seemed more appropriate to use a modern design programme such as ‘Wellcat’. The programme incorporates five modules. The WT-Drill module lets the user evaluate the temperatures and pressures during drilling and the casing installation stages, while the resulting stresses the casing is subject to are calculated using the WS-Casing module. The WT-Circ and WT-Prod modules let the user evaluate the temperatures during standard production and circulation operations and the WS-Tube module lets the user calculate tubing movement and stress. ‘Wellcat’ can be used for single completions, selective completions with a maximum of five packers, dual completions with a maximum of two packer’s and dual selective completions. The programme also assesses the installation of a hanger in the completion as well as hydraulic or mechanical packer setting. It is possible to evaluate the reduction in material rating due to temperature and any anistropy of materials. The calculation of load losses and the hydraulic conditions can be carried out using different correlations which are valid for two-stage flow (Beggs & Brill, Orkiszewski, Gray, Hagedorn & Brown, Duns & Ross), while the Govier-Aziz formula is used for single stage fluids. The most interesting feature of the programme is its capability to evaluate temperatures during and after well operations. During testing the results were compared to actual field data and a good match was obtained. It is also possible to calibrate the average coefficients for thermal exchange and specific heat, once the temperature profile and lithology of the formations are known. ‘Wellcat’ produces results in ASCII format, which can be read, printed or exported as graphic files. During processing it is also possible to display and print a simple drawing of the well and the completion. The ‘Wellcat’ programme was initially tested with the most typical cases (discussed in publications) and appropriate comparisons were made with data previously obtained using the ‘Vertubing’ programme with reasonable results. The programme is now used in the company for completion string design and at present available in PC, VAX Mainframe and UNIX versions.

Eni Completion Design Manual (Petroleum,Oil,Gas)

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