Oil And Gas Well Completions

Oil and Gas Well Completions WPS - Kellyville Training Center

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Completion – Definition

Definition: The methodology and technology required to produce recoverable reserves (reservoir to surface). Process: The design, selection and installation of tubulars, tools and equipment, located in the wellbore, for the purpose of conveying, pumping or controlling production (or injection) fluids.

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Fundamental Requirements A completion system must provide a means of oil or gas production which is: • Safe – e.g., well security, environment • Efficient – e.g., production objectives • Economic – e.g., cost vs. revenue

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Completion History/Evolution • 1300 Marco Polo – wells dug at Caspian Sea • 1814 First naturally flowing oil well – 475 ft • 1822 Rudimentary art of drilling established • 1905 Casing cemented • 1911 First gas lift device • 1913 First dual completion • 1926 First electric submersible pump • 1933 First gun perforation job • 1969 Commercial coiled tubing services introduced

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Completion System Design

Openhole or Cased Hole

• Gross production rate • Well depth and reservoir Eruptive or Pumped

Single or Multiple Zone

• • •

pressure Formation properties Fluid properties Well location

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Openhole Completions (Barefoot)

• Conductor with openhole – No ground water protection

Cap Rock

• Casing string with openhole

– Provides top-hole stability

• Liner with openhole

– Cross-flow protection

Reservoir

Openhole Completion

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Gravel Pack Completion

Perforated Completions • Casing or liner – Without production tubing

• Casing or liner with •

Cap Rock

production tubing – Production through tubing or annulus Casing or liner with tubing and packer – Production through tubing, enables flow control

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Reservoir

Cemented casing

Cemented liner

Modern Completion Configuration

• Four zone selective production system • Dual production strings • Commingled or alternate production •

controlled by sliding sleeves System contains 28 major downhole components

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Factors Affecting Well Performance

• 1 Reservoir boundary – Can be estimated

• 2 Reservoir properties – Can be measured

• 3 Completion

– Can be controlled

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Vertical Wellbore Profile

Vertical wellbore • No great productivity benefit • May catch unwanted water or gas • Preferred for fracturing

Cap rock

Basement

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Deviated Wellbore Profile

Deviated wellbore • Increased productivity especially in thin reservoirs • Extends reach within reservoir

Cap rock

Basement

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Horizontal Wellbore Profile

Horizontal wellbore • Significant increase in productivity • Reduced influence of skin • Reduced influence on coning

Cap rock

Water zone

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Oil and Gas Well Completions

Completion Design and Engineering

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Multiphase Fluid Flow Principal multiphase flow regimes recognised in oil and gas wells: • Bubble flow • Slug flow • Transition or churn flow • Annular or mist flow

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Bubble Flow Bubble flow characterized by: • Small evenly distributed gas bubbles • Continuous liquid phase Further categorized as: • Bubbly flow • Dispersed bubble flow

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Small gas bubbles evenly distributed throughout liquid phase

Slug Flow

Slug flow characterized by: • Series of gas pockets between slugs of liquid • Continuous liquid phase • Taylor bubbles

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Bubbles of varying size unevenly distributed throughout liquid phase

Annular/Mist Annular/mist flow characterized by: • Continuous gas phase • Entrained liquid in gas flow (mist) • Annular liquid film

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Continuous gas phase Annular fluid film

Transition/Churn Flow

Transition flow characterized by: • Chaotic flow pattern • Neither phase is continuous • Liquid appears to move both up and down the conduit

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Chaotic flow pattern

Evaluating Pressure Losses Surface choke

Separator Node

Wellhead Node

Liquid

SSSV Downhole restriction

Gas

Reservoir Node (near wellbore)

Wellbore Node

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Reservoir Node (boundary)

Tubing String Specification Tubing strings specified by the following: • Size and dimensions – OD – Weight and wall thickness – Coupling OD • Material grade – Minimum yield strength • Construction – Seamless/electric welded pipe • Tool joint – Nonupset/Upset – Premium thread 20

Tubing Connections - Collar

Non-upset (8 round) Connection

External Upset Connection 21

Tubing Connections - Integral

EUE Integral Connection

Hydril Integral Connection 22

String Design Factors Criteria for string selection/design include: • Pressure and tension – < 80% of tubing yield strength – burst and collapse pressure limitations • Production rate – flowrate should be compatible with flow area • Wellbore environment – fluid properties, e.g., corrosion, wellbore deposits • Tubular connections and geometry – e.g., tool joints and annular clearance • Force and stress – throughout the life of the completion 23

Tubing Forces Forces and stresses on the completion can be effected by: • Temperature – temperature changes • Pressure – pressure changes • Weight of components • Fluid density and gradients • Friction – especially in deviated wellbores

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Tubing Movement- Packers

Free motion

Limited motion 25

No motion

Buoyancy

A

1 Open tubing

A

A

B

B

C

C

2 Tapered string

3 Tapered string 26

D

4 Plugged string

Length and Force Changes Length and forces changes should be assessed to enable: • Selection of an appropriate packer • Assessment of potential tubing damage • Accurate space out and landing of the completion Four principal causes of length and force changes: • Piston effect • Buckling effect • Ballooning effect • Temperature effect

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Buckling Effect

Neutral point

R

Casing wall contact

R=

Bowed tubing

Compression buckling

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Casing ID - Tubing OD 2

Radial clearance

Pressure Buckling

High pressure

Tubing deflection acts to increase tension

Low pressure

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Ballooning Effect

High pressure Acts to shorten the string increasing tension Low pressure

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Reverse Ballooning

Acts to lengthen the string reducing tension

Low pressure

High pressure

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Temperature Effect

Neutral (As installed)

ICE Cooling increases tension

HEAT HEAT

Heating reduces tension

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Tubing Stress Calculations Completion fluid

Produced fluid

Treatment fluid

Completion fluid

Completion fluid

Completion fluid

Seal assembly on down-stroke

Seal assembly on up-stroke

Mid stroke setting

1 Installation

2 Production 33

3 Treatment

Material Selection Factors influencing material selection criteria typically include: • Mechanical properties – e.g., material strength • Operating environment – e.g., sour or corrosive service • Ease of manufacture • Cost • Availability – e.g., in required dimensions

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Corrosion Failure mechanisms associated with corrosion: • Stress corrosion cracking – Hydrogen embrittlement, stress cracking • Material weight loss – CO2 corrosion, oxidization, treatment fluids • Pitting or localised loss Requires three conditions • Corrosive media, e.g., oxygen • Electrolyte, e.g., moisture • Heat or pressure

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Elastomers and Plastics General definition: An elastomer can be stretched to at least twice its original length and will quickly return to approximately its original length on release. Plastics cannot withstand such strain without permanent damage. Primary applications: • Sealing components for: – pressure – fluids (liquids and gas) – heat

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Elastomer and Plastic Limitations Elastomers and plastics should be selected on compatibility with: • Corrosive fluids or environment – e.g., reservoir or completion fluids • Chemical compatibility – e.g., stimulation fluids • Operating temperature – including range and fluctuation • Operating pressure – including range and fluctuation • Dimension – e.g., ability to function with extrusion gap 37

Perforating The process of creating a clear channel of communication between the reservoir and wellbore. Technique selection depends on: • Completion type and dimensions • Reservoir conditions, e.g., stability/consolidation • Local experience and preference

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Perforation History

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Perforation Program Design Principal design considerations include: • Location of the perforated interval • Shot density • Perforation phasing • Penetration • Perforating debris • Gun conveyance method • Gun recoverability • Bottom hole perforating pressure

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Perforating Gun Components Principal perforation gun/system components: • Charge carrier – recoverable, disposable • Detonator – electrical or percussion (dependent on conveyance) • Detonating cord – provides link between charges • Shaped charge – generates high pressure jet

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Perforation Charge Charge liner

Stand-off Damaged zone

Explosive charge

Primer and detonator cord Charge case

Gun body

Cement

Charge components 42

Reservoir formation

Perforation Process

Extremely highpressure jet

Crushed zone

Perforation debris

Clean, stable perforation tunnel

Perforation sequence 43

Perforating Gun Systems Perforating gun or system options include: • Gun conveyance method – wireline, TCP or coiled tubing • Thru-tubing gun systems – small OD systems • Casing gun systems – large OD systems • Tubing conveyed gun systems – recovered or dropped – suitable for long intervals – no verification 44

Perforation Phasing

Penetration

Perforation phasing

Stand-off

Stand-off

Penetration

Effects of perforation phasing 45

Perforation Phasing Perforation phasing describes the angle between shots. Key considerations include: • Five common configurations - 0o, 60o, 90o, 120o, 180o • phased guns require decentralizing • Near wellbore flow characteristics effected by phasing • Oriented phasing may be desirable, e.g., hydraulic fracturing treatments

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Penetration, Stand Off and Debris Penetration - effective length of perforation channel • Should bypass damaged zone • Effected by stand-off Stand Off - distance between gun and casing/liner • Charge efficiency diminishes with distance • Effects accentuated at high pressures • Perforation size effected by stand off Perforation debris - left in place after perforating • Some debris inevitable - dependent on gun/charge type • Should be removed by back flush after/during perforating

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Bottomhole Perforation Pressure Two basic bottom hole pressure conditions associated with perforating: • Overbalanced - perforating with kill weight fluid column in wellbore – Surge following perforation acts to compact debris – Requires less complex equipment and techniques • Underbalanced – Removes perforation debris at time of perforation – Reduces likelihood of near-wellbore damage – Requires special equipment and techniques A third Pressure condition is being used in the last years: • Extreme Overbalanced Perforation ( EOB ); The wellbore pressure in the wellbore is higher than the Frac Gradient. 48

Oil and Gas Well Completions

Types of Completion

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Completion Design Factors Principal completion design factor include: • Casing protection – e.g., protection against erosion, corrosion • Tubing string removal – e.g., for replacement or workover • Safety or contingency – e.g., requirements for safety valves and well kill • Production control – e.g., components providing flexibility and control of production (nipples, profiles and sliding sleeves

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Basic Production Configurations Majority of completions are based on the following completion configurations • Reservoir interface – Openhole – Casing production – Liner production – Gravel pack wellbore • Production conduit – Suspended tubing – Basic packer – Packer and tailpipe – Packer with additional safety and production devices 51

Open Hole Production Key points • No downhole flow control or isolation • Producing formation is unsupported • Casing provides isolation between shallower formations

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Casing Production Key points • No downhole flow control or isolation • Casing provides isolation between shallower formations with potential for remedial work to isolate sections of perforated interval

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Liner Production

Key points • Similar to casing production but with smaller (and shorter) tubulars set through the reservoir

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Gravel Pack Wellbore Key points • Special application requirement determined by formation type • May require special operation (underreaming) during well construction phase

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Simple Tubing Completion

Key features • Circulation capability (well kill or kick-off) • Improves hydraulic performance • Limited protection for casing

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Basic Packer Completion Key features • Circulation capability (determined by design and setting of packer) • Casing string protected from fluid and pressure effects

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Packer with Tailpipe Key features • Additional flexibility for downhole production (flow)control, e.g., plugs • Facility for downhole instruments (gauges)

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Enhanced Packer Installation Key features • Improved flexibility for downhole production control, e.g., plugs above or below packer • Circulation capability independent of packer • Safety facility (SSSV)

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Completion Examples The following completion examples are extracted from design files for: • Single zone completions • Multiple zone completions • Liner completions • Special completions – Sand control – Inhibitor injection – Waterflood – Thermal – Remedial (scab liner)

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Single Zone – Retrievable Packer Key Features • Tail-pipe facility for pressure and temperature gauges • Fully retrievable completion • Packer can be set with well flanged up • Thru-tubing perforation possible where size permits

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Single Zone – Seal-Bore Packer

Key Features • Seal-bore packer set on electricline or tubing • On-off connector and tubing anchor allows tubing to be retrieved • Tailpipe plugged and left in wellbore or retrieved with production tubing

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Single Zone – Packer and Tailpipe

Key Features • Tailpipe plugged and left in wellbore when production tubing is retrieved • Permits safe thru-tubing perforating • Block and kill system facilitates the killing of high-pressure, highflowrate wells

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Single Zone – Casing Seal Receptacle

Key Features • Expansion joint allows for tubing movement • Tailpipe retrievable (separately) • Protective sleeve run in CSR during primary and remedial cementing

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Multiple Zones – 2 Zones 1 Packer

Key Features • Separate or commingled production through single tubing string • Blast joint protection across upper interval • On-off connector and tubing anchor permits tubing retrieval with lower interval isolated

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Multiple Zones – 2 Zones 2 Packers Key Features • Independent production through dual tubing strings • Blast joint protection across upper interval • Both packers retrievable • Tailpipe instrument facility on both strings • Thru-tubing perforation of lower zone possible

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Multiple Zones – 3 Zones 3 Packers Key Features • Several zones produced through one tubing string • Flow controlled by wireline retrievable choke/check valves • By-pass sliding sleeve prevents communication during service work • Up to five zones have been produced using this method

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Multiple Zones – 4 Zones 4 Packers

Key Features • Four zone selective production system • Dual production strings • Commingled or alternate production controlled by sliding sleeves • System contains 28 major downhole components

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Liner CSR

Key Features • Most simple liner hook-up • CSR replaces packer • Fluid circulation through sliding sleeve above the liner hanger • Tailpipe retrieved with production tubing

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CSR and Seal-Bore Packer

Key Features • Liner top/lap is permanently isolated • Fluid circulation through sliding sleeve above the packer • Tailpipe can be plugged to allow retrieval of the production tubing

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Special Service Completions

Special completion examples include: • Sand control • Inhibitor injection • Waterflood • Tubing/casing repair

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Gravel Pack Completion Key Features • Tools set and gravel placed using a service tool and tubing workstring • Gravel squeezed into perforation tunnels • Production tubing stung-in to production seal-assembly • Specialised service typically involving dedicated service equipment and personnel

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Inhibitor Injection

Key Features • Side pocket mandrel injection permits protection inside production tubing above the packer • Injection nipple and small diameter injection line is suitable for shallow applications

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Inhibitor – Complete Protection

Key Features • Parallel flow tube and seal-bore packer enables inhibitor to be pumped down short string • All flow-wetted completion components are exposed to inhibitor fluid • Inhibitor flow controlled at surface

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Waterflood

Key Features • Two injection zones treated with both flow control regulators located at surface • Totally separate injection systems

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Waterflood – Thick Injection Zone

Key Features • Injection efficiency in thick zones is improved by using multiple injection points • Downhole flow regulation helps prevent premature breakthrough between intra-zonal sections

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Thermal Completion – Steam Injection

Key Features • Packer incorporates an integral expansion/slip joint assembly • SPM allows insulation material to be circulated into annulus

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Remedial Completion – Scab Liner

Key Features • Isolation of damaged casing/liner or abandonment of a depleted zone • Hydraulic set packers at top and bottom of scab liner • On-off connector on lower sealbore packer allowed installation with the lower perforations isolated throughout the operation

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Monbore Completion Key Features • Designed to meet criteria for: – appropriate production rates – flexibility/contingency – safety – monitoring (reservoir management) – longevity

Safety valve

Packer/hanger assembly

Liner

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Multi-Zone Completion Hyd rau lic Co ntrol L in e for th e TRS CS S V Tub in g Retreivab le S u rfa ce Co ntroled S ub su rfa ce S afety V a lve (TRS CS S V ) Hyd rau lic Co ntrol L in e for th e A S V

E xam ple of a M ulti Zone C om pletion using a S tandard C onfiguration for each Zone (th is ca n b e re p e a te d fo r a n y n u m b e r o f zo n e s)

A n nu la r S afety V alve (A S V ) S yste m with W e t Discon ne ct

1 0 3 /4 Ca sin g

G a s Lift Man dre l 5 -1/2 P ro du ctio n Tu bing P rod uction P a cke r w/ TE C b ypa ss Tub in g E nca se d Co nd ucto r (TE C)

Iso la tio n P a cke r w/ TE C fe ed th ru

Flo w Co n tro l Device w/ In te gra l P re ssu re / Temp era tu re sen so r

Cross Co up ling Cla mp V e nturi Flo wme ter

P lug 9 -5/8 L in e r

Zon e 2

Zon e 1

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Artificial Lift – Objectives

The primary purpose of installing an artificial lift system is to maintain a reduced bottom hole pressure (drawdown) to enable the desired reservoir fluids to be produced at an acceptable rate.

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Reasons for Artificial Lift • Compensate for declining reservoir pressure – i.e., maintain an acceptable production rate

• Offsetting the effect of increasing water production • Overcome high friction pressures associated with the • • •

production of viscous or waxy crudes Kick-off high gas-liquid ratio wells that die when shut in Reduce the effect of flowline back pressure Maintaining a production rate which reduces wax or scale deposition

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Artificial Lift Selection The selection of an appropriate (optimal) artificial lift system is dependent on: • Inflow performance of the well/reservoir • Capacity and operation of the artificial lift system(s) • Capital cost • Operating cost • Servicing frequency (maintenance cost)

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Artificial Lift – TPC

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Artificial Lift Methods Commonly used artificial lift methods include: • Rod pump • Gas lift • Electric submersible pump • Piston pump • Jet pump • Plunger lift • Other specialist or adapted systems

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Rod Pump • Rod pumps account for • •

approximately 60% of onshore artificial lift completions Industry accepted – Economic in ideal field – Not gas dependent Limited efficiency – Maintenance intensive – Vertical wellbores

Rods

Productio n tubing

Rod pump

Tubing anchor

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Rod Pump - Surface Equipment Horsehead

Walking beam

Stuffing box and polished rod Prime mover Production valve

Gearbox and counterbalance

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Gas Lift • Gas lift accounts for • • • •

Production tubing

approximately 90% of offshore artificial lift completions System may be designed to suit most wells Wireline serviceable Few mechanical parts Sand and fill tolerant

Production tubing

Gas lift valve installed inside pocket mandrel Retrievable packer No-go seating nipple Wireline entry guide

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Electric Submersible Pump • Extremely high liquid • • •

Armored cable

production capability High installation and operating cost Suitable for low gas-to-oil ratio applications only Electrical components easily damaged

Cable guard Sliding sleeve Dual string retrievable packer (modified)

Sliding sleeve No-go seating nipple Pump assembly (various) Pump Intake Protector Motor

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Hydraulic Systems Hydraulic pumping systems - two main categories • Piston pump – close coupled engine/pump assembly with positive displacement pump – performance determined by the pump/engine size • Hydraulic jet pump – imparts energy to the production fluid – relatively tolerant of lower quality power fluid or produced fluids

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Hydraulic Pumping Systems

Piston pump system

Jet pump system

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Plunger Lift • Suited to high GLR wells (low liquid production) • Efficiency decreases with depth and PI • Efficiency increase in larger tubing sizes (where liquid slippage is more prevalent) Other Systems • Screw pump – operates on same principle as PDM • Turbine pump – similar to ESP installations

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Plunger Lift System Downhole Equipment

Plunger (with liquid load Intermitter or controller

Plunger catcher

Tubing stop Injection gas Production

Standing valve

Tubing stop

Surface Equipment

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