petroleum production concepts- conventional completions

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Revised 2010 HWU MSc. PT - David Davies

Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, U.K.

Production Technology

David Davies


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Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, U.K.

Completion Concepts

D. R. Davies


Chapter 1: Learning Objectives

1. Selection criteria for:

– Bottom Hole Completion Technique

– Flow Conduit between Reservoir & Surface

2. Describe:

– Completion String Components & their Function

– Multiple Zone Completions

3. Wireline Servicing of Completion Accessories

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Design & Completion Objectives for Production & Injection Wells

1. Provide optimum production/injection performance.

2. Minimise the total costs per unit volume of fluid produced or injected

– minimise the cost of initial completion, maintaining production & any remedial measures

3. Ensure safety.

4. Maximise the integrity and reliability of the completion over the envisaged completed well life


Well Integrity includes:1. Well Construction Integrity:

– Wellhead & X-mass tree– Casing & Cement Integrity (CBL, Zonal Isolation etc.)– Casing Corrosion Logs

2. Completion Integrity Assurance:– Wellhead & Christmas tree– Down Hole equipment (Safety Valve, Sliding Side Door, Dual

or Single Packer either Permanent or Retrievable, etc.)– Artificial lift (Gas Lift or Pump)

3. Flow Assurance– Scale, Asphaltene, Corrosion Management, Etc.

4. Well Life Cycle Management

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Examples of Well Integrity

Failures


Introduction• The fundamental design of a completion consists of four

principal decision areas:

1. Specification of bottom hole completion technique.

2. Selection of the production conduit.

3. Assessment of completion string facilities.

4. Evaluation of well productivity &/ or injectivity

• Followed by:

1. Specification of all equipment and materials

2. Optimisation of completion inflow performance

3. Optimising total well design.

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Completion Strategy Design


Open Hole or Barefoot Completion

• Simple/low cost completion

• Drawback - all zones open to (cross)flow, no control

• Consolidated formations only:a) E.g. deep wells with depletion

driveb) Naturally fractured reservoirs

e.g. limestonec) Long completion intervals or

limited access. E.g. horizontal & multi lateral wells

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Slotted Liner/Wire Wrapped/ Expanding Screen Completion

• Drawback1. All zones open to (cross)flow,

no control

2. Screen may become plugged

• Controls sand production from weaker formations:1. Reservoirs with large &

homogenous sand grains

2. Long completion intervals or limited access e.g. horizontal & multi-lateral wells


Cemented & Perforated Production Liner/ Casing

• Liner has lowest cost

• Commonest type of completion

• Inflow selectivity achieved by careful positioning of perforations if cement hydraulically seals casing annulus

• Multi-zone completions possible

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Production Conduit Options

Tubingless Casing FlowTubinglessCasing Flow

Casing & Tubing Flow orTubing Flow without

annulus isolation

Tubing Flow with annulus isolation


Tubingless Completion Flow

• Provides maximum production rate BUT

1. The well must be killed by squeezing

(injecting) the wellbore contents into the

formation along with any rust, scale, etc.

reducing the permeability

2. May require high fluid pressures & potential

for possible casing burst

3. Need to overcome the tendency of the

denser kill fluid to “fall” through the low

density hydrocarbons during the operation

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Tubing and/or Casing Flow

• Highest production rates achieved by

combined Tubing & Annular flow

– Beneficial for high PI wells

• Deep circulation capability allows annulus

& tubing contents to be circulated to surface

(U-tube) during well killing

– Lower pressures than for squeeze kill

– No need to inject into reservoir

• Casing corrosion & erosion still possible


Tubing Flow without Annulus Isolation

• Tubing Flow only gives some protection to

casing & phase slip reduced

• Gas accumulates in annulus if FBHP<

Bubble Point

– Gas eventually fills the annulus leading to

annulus heading when gas slug flow up the

tubing at regular intervals

• Casing exposed to produced fluids

– But corrosion inhibitor can be continuously

injected into annulus if required

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Tubing Completion Flow

• Most widely used completion type for naturally flowing wells

• Packer isolates annulus with compressed or inflated rubber elements

• Packer located close to top of reservoir

– Minimises trapped annular gas volume below the packer.

• Well killing via circulation port in tubing OR punch hole in tubing

Packer


Basic Well Completion Schematic

• Pressure & Flow Containment

• Annulus Isolation

• Downhole Closure of the tubing below the wellhead

• Circulation between Annulus & Tubing

• Tubing Isolation

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Completion String must be able to:

1. Withstands anticipated pressures during production and well operations e.g. stimulation

2. Produce or inject into the reservoir with minimal loss of flowing pressure

3. Minimise reservoir fluid contact with the production casing (annulus isolated from the production tubing)

4. Remotely shut-off flow downhole when required.

5. Selectively circulate between annulus & tubing.

6. Install a plug in the tubing e.g. for pressure testing.


The General

Well Completion

Scheme

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Casing Spool Well Head Assembly

• Suspend casing and tubing strings• Support surface closure/flow control device:

i) Blow-out preventer stack whilst drillingorii) Xmas tree for production or injection

• Provide Hydraulic access to the annuli between :(i) Casings for cement placement(ii) Production casing & tubing for well circulation


Christmas tree placed on top of well head

assembly

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A basic Xmas Tree

• Xmas tree controls the flow of produced or injected fluids• Attached to wellhead after installing the production tubing.• Two wing valves - for production & well killing (injection)• Snubbing, wireline or coiled tubing access via swab valve• Master valve controls all hydraulic & mechanical access to well

• Often duplicated to increase well safety • Valves may be manual, electical or hydraulic operated.


The Production Tubing

Tubing is not just a “piece of pipe”!

• It is special equipment manufactured to a high

standard to withstand high mechanical stresses,

fluid pressures & temperatures for long periods in

an often corrosive environment

• Failure to select & correctly install a suitable tubing

results in expensive workovers or loss of the well

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The Production Tubing must be specified to:

1. Minimise pressure losses (tubing internal diameter).

2. Have sufficient tensile strength to allow suspension of the complete string without tensile failure.

3. Withstand the maximum conceivable internal pressure

4. Withstand the maximum conceivable collapse pressure

5. Resistant to chemical corrosion from the produced or injected fluids, Corrosion reduces the tubing’s strength, potentially leading to the above failures


The Production Tubing1. Many grades of steel are available e.g. N80, C75etc.:

– N, C, etc. defines the composition & heat treatment

– Figureis the minimum tensile strength (1,000s psi)

2. Tubing size defined by its outside diameter

3. Tubing wall thickness defined by its weight/foot

4. Both tubing & coupling type define the completion string’s tensile strength & hydraulic integrity

Full Tubing Specification

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Two types of Threaded Couplings:

1. Internal pressure necessary to produce a pressure seal.

• E.G. API round thread &buttress connections

• Thread compound (or pipe dope), applied to the threads, is compressed by external pressure acting on the coupling & fills any void spaces in the coupling.

2. Premium metal-to-metal or elastomeric connections

• E.G. Extreme Line, Hydril or VAM thread designs.

• Seal is generated by torque bringing together seal shoulders or a tapered surfaces within the thread itself

• VAM developed for completing high pressure gas wells where rigorous sealing & pressure integrity is essential


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A box type tubing

connection


• Production Packer’s annular seal: 1. Improves flow stability &

production control2. Protects the outer pressure

containment system (production casing/wellhead)

3. Selectively isolate zones e.g. two producing zones of different fluid properties, GOR, pressure, etc.

Annular Pressure Seal (Packer)

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(1) Retrievable Packers can be easily retrieved.

– Packer integral part of the tubing string

– Run to the setting depth

– Setting mechanism actuated

(2) Permanent Packer cannot be easily retrieved.

– Usually run & set separately e.g. on wireline

– Run with or without a tailpipe

– Tubing is run later, pressure seal achieved by

– Part of the packer milled away, allowing the rubber element to collapse & the packer retrieved

Packer Retrievability

Revised 2010 HWU MSc. PT - David DaviesPermanent Packer system includes Anchor & Mill Out Extension

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• Packer setting involves compression & extrusion of arubber element:

• Mechanically – e.g. by rotation of tubing string.

• Compression or Tension - based on weight of tubing

– A mechanical device transfers the force to compress the rubber element.

Packer Setting Mechanism


• Sealing elements compressed against casing wall

• Slips grip casing wall due to downthrust of lower cone

• Unidirectional sealing & resistance to tubing movement

A Compression Set Packer

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• Packer setting involves compression & extrusion of arubber element:

• Mechanically – e.g. by rotation of tubing string.

• Compression or Tension - based on weight of tubing

– A mechanical device transfers the force to compress the rubber element.

• Hydraulic – Ball plugs tubing below the packer. Pressure sets the packer without being exerted on the formation or annulus

• Electrical - Packer & tailpipe lowered on electric line to the setting depth. A small explosive charge is detonated to actuate the packer setting mechanism

Packer Setting Mechanism


Dynamic Tubing Seal Assemblies allow Tubing Movement

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• Tubing Anchor prevents tubing movement without sealing the annulus

• Static Packers use “metal-to-metal” rather than elastomer to achieve a pressure seal– Suitable for gas wells– Tubing has to be run under

tension to avoid tubing buckling when well placed on production

Tubing Anchor & Static Tubing Seal Packer


Subsurface Safety Valve

Provides a remote, failsafe, shutdown system of sub-surface isolation for catastrophic Xmas tree failure

Manages:• Xmas tree removal while preparing to pull tubing

• Removal of valves or valve components for servicing

• Accidental damage to Xmas tree

• Wellhead leaks at the Xmas tree flange seals

1. Direct Controlled SSSV (or "storm chokes“) close well when preset pressure drops or flow rates exceeded OR

2. Surface Controlled SSSV (SCSSSV) closes well by loss of hydraulic pressure to the downhole valve assembly.

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Wireline Retrievable ScSSSV

• Valve nipple is part of the tubing string

• Valve assembly is run & retrieved by wireline

• Valve has smaller flow diameter than the tubing

Valve Action• Valve held open due to hydraulic pressure

• Pressure acts on a piston which moves a flow tube against the ball after pressure equalisation

• Valve closure occurs on loss of hydraulic pressure

• A spring ensures reverse movement of the piston & flow tube


Surface Controlled Sub-Surface Safety Valve Operation

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Surface Controlled Sub-Surface Safety Valve

• Ball valve held in open position by

control line pressure during

normal operation• Ball valve closes

to seal tubing when pressure lost

e.g. in an emergency


Flapper ScSSSV is an alternative to the ball valve

Valve fully closedValve fully open

closed

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Surface Controlled Subsurface Safety Valve

Provides a remote, failsafe, shutdown system of sub-surface isolation for catastrophic Xmas tree failure

• Allows:• Xmas tree removal while preparing to pull tubing

• Removal of valves or valve components for servicing

• Accidental damage to Xmas tree

• Wellhead leak at the Xmas tree flange seals

2. Surface Controlled SSSV (ScSSSV) opens well by

hydraulic pressure fed to the downhole valve

• Hydraulic pressure via a 0.25 in. control line in annulus


– Many types of Valve can be installed in a Side Pocket Mandrel:• Gas Lift Valve• Dummy Valve• Chemical Injection Valve• Circulating Valve• Differential Dump/Kill Valve• Water Injection Control Valve

Side Pocket Mandrel

Valve Body

No restriction to tubing

access

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Aligning the outer & inner ports by moving the sleeve allows circulation from tubing to annulus. E.g. to kill the well

Wireline Operated Sliding Side Door

permitted


Landing Nipples

Applications: 1. Isolate the tubing string

2. Ported device for tubing & annulus communication

3. Emergency closure of tubing

4. Downhole regulation or throttling of the flow.

5. Install downhole Pressure or Temperature recording gauges

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Landing Nipples

1. Isolate the tubing string




5. Install downhole P or T recording gauges

Two types of application• Nipples installed at various points in the string for:

(a) Plugging the tubing for:

Pressure tests, Setting Hydraulic packer & Zonal isolation


Landing Nipples

1. Isolate the tubing string




5. Install downhole P or T recording gauges

Two types of application• Nipples installed at various points in the string for:

(a) Plugging the tubing for:

Pressure tests, Setting Hydraulic packer & Zonal isolation

(b) Installing flow control equipment:

Downhole chokes, SSSVs & pressure recorders

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Landing Nipple

Installing flow control equipment:

Subsurface Flow control valve

• Nipples can be of two types:

- No-go: nipple size decreases down string

(Largest nipple placed on top)

- Selective Nipples

Multiple, same size nipples use selective locking mechanism


Flow Coupling

• A 2 - 4 ft length of heavy

walled tubing installed in areas

where excessive turbulence

expected

• E.G. above & below cross-

overs, landing nipples, ScSSSV,

sliding sleeves, etc.

• Provides extra protection

against internal erosion

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Completion Equipment

Perforated Flow Tube

• Allows fluid to enter when the a

plug is installed at the base of the tail

pipe. E.g. by pressure gauges

Courtesy Schlumberger

Wire Line Entry Guide (WEG)

• Provides easy re-

entry of wireline

tools into tubing


General Well

Completion Scheme

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Multiple Zone Completions


Multiple Zone Completions

(a) Comingled Flow:

• Multiple zones flow at the same time into the tubing

e.g. two zones producing via a single tubing string

(b) Alternate Zone Well Completion:

• Only one zone flows into the tubing at any time

• Lower zone produced first

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(Selective)Single StringDual Zone,

Two Packers

• Two zone completion using one tubing string to commingle both zones or selectively produce each zone


Alternate Zone Well Completion Strategy

Advantages(1) Effective control of all aspects of reservoir depletion

and well control.

(2) Depletion strategy can be easily changed to adapt to new situations. E.g. change a producer to an injector.

(3) One well’s problems do not production from other zones/wells.

(4) Each well is relatively simple mechanically

– risk of failure due to complexity minimised.

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Alternate Zone Well Completion Strategy

Disadvantages

(1) More wells required to achieve the same degree of

depletion control

- Greater cost for same drainage reservoir efficiency

(2) Zonal productivity differences will defer production &

extend field life unless well count increased

– Increase unit production costs.


Co-mingled Zonal Flow

(a) Advantages:(1) Minimises well numbers & capital investment.

(2) Reduced drilling time accelerates production build-up

(b) Disadvantages(1) Mixing of produced fluids can give problems:

(a) Corrosion/erosion: acids, H2S, CO2, produced sand.

(c) Different composition of fluids & economic value

(d) Different zonal WOR and GOR will influence the tubing vertical lift performance

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Co-mingled Zonal Flow

(b) Disadvantages (continued)

(2) Poor performance of the less productive/lower pressure

reservoirs due to inflow from more productive zones

(3) Control of individual zonal production not possible.

(4) Fluid injection, e.g. for stimulation, cannot easily be

diverted into required layer.

(5) Total well production influenced by change in

characteristics of one zone. E.g. increased WOR


Multizone Completion Options

(a) Comingled Flow:

• Multiple zones flow at the same time into the tubing

e.g. two zones producing via a single tubing string

(b) Alternate Zone Well Completion:

• A single zone flows into the tubing at any time

• Lower zone produced first

(c) Segregated, Multi-Zone Flow:

• Multiple production conduits within the same wellbore

• Each tubing produces one zone only

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• Separate tubing

string for each zone

• Production from

each zone monitored

& controlled.

• Suitable completion

for problem well

fluids

Dual String, Dual Zone


Segregated Multiple Zone Depletion

Advantages(1) Zonal production rates independently controlled.

(2) Changes in the production characteristics of one zone

will not influence the others.

(3) Some remedial work possible for individual zones

(stimulation, re-perforating, etc.)

(4) Continuous zonal monitoring possible gives better

reservoir management.

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Segregated Multiple Zone Depletion

Disadvantages

1. Additional CAPEX & rig time required to install the

extra tubing string.

2. Smaller tubing sizes reduces well total flow capacity.

3. Increased mechanical complexity increases the chance

of equipment failure.


Dual Zone Completion

Options

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Extra Equipment for Dual Completions

• Dual Tubing Head Hangers

• Dual Packers

• Blast Joints installed in tubings placed opposite upper zone perforations


Min Max MD-RKB TVD-RKB

ID" OD" ft ftTubing hanger 350

10 3/4" Casing 5.5", 17 ppf tubing 4.767 5.953

1/4" Encapsulated control lineFlow coupling 4.767 5.953SSV: T-5EMS TRDHSV w / 3.5" AF Profile 3.500 9.200 850

Flow coupling 4.767 6.0725.5" Pup Joint 4.767 5.9535.5", 17 ppf tubing 4.767 5.953

10 3/4" x 9 5/8" X-over5", 18 ppf Tubing 4.151 5.364 1000 1000

5.5" Tubing 4.767 5.953 1500 1500

2700 2695

5-1/2" Flow Coupling 4.767 6.0725-1/2"Pup Joint 4.767 5.9535-1/2"Pup Joint 4.767 5.953Polished Bore Receptacle 4.872 8.125 39445-1/2" Pup Joint 4.767 5.364 3950KC1-22 Anchor 4.884 6.468 39579 5/8" SAB-3 Packer 4.750 8.150 39727" MOE (Mill-Out Extention) 6.185 7.027 3988X-over, 7" New Vam B x 5" Fox RS P 4.151 7.693 4000 39895" Pup Joint 4.151 5.3645" Pup Joint 4.151 5.3645" Flow Coupling 4.151 6.0724.135" AOF Wireline Nipple 4.135 6.050 41025" Flow Coupling 4.151 6.0785" Pup Joint 4.151 5.3645" Tubing Joint 4.151 5.3645" Pup Joint 4.151 5.3645" Flow Coupling 4.151 6.0774.125" AOF Wireline Nipple 4.125 5.950 47655" Flow Coupling 4.151 5.3645" Pup Joint 4.151 5.3645" Tubing Joint 4.151 5.3645" Pup Joint - perforated 4.151 5.3645" Flow Coupling 4.151 6.1244.000" AOF Wireline Nipple 4.000 5.950 55005" Flow Coupling 4.151 6.0775" Pup Joint 4.151 5.3645" Tubing Joint w ith centraliser 4.151 5.3645" Pup Joint 4.151 5.3645" Tubing Joint 4.151 5.364Wireline Reentry Guide 4.151 5.451 5600 55777" Liner 6.059 7.512 5600 5577

6.059 7.5126.059 7.5126.059 7.5126.059 7.5126.059 7.5126.059 7.5126.059 7.512

Completion Schematic

•Equipment listed include:

• Pup joints• X- Overs etc.

OD’s, ID’s & Depths

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Well Completion Design

• Well characteristics such as:

(a) pressure, (b) productivity or injectivity index, (c) fluid properties & (d) rock properties and geological data.

• Geographical factors such as:

(a) location, (b) water depth (if offshore), (c) weather conditions & (d) accessibility.

• Operational design constraints such as:

(a) environmental regulations & (b) safety aspects

• The number of producing zones.


Wireline Servicing of Completion Accessories

• Typical Wireline applications:1. Installation of completion equipment prior to running

the production tubing e.g. a packer and a tailpipe.

2. Installation or retrieval of equipment within the tubing string e.g. valves, pressure gauges, etc.

3. Operation of downhole equipment to either divert or shut off fluid flow. e.g. open a SSD, install bridge plug

4. Removal of materials which have built up in the tubing string e.g. wax or sand.

5. Adjustment of the completion interval (perforating)

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Wireline can work on a “live” well

• Wireline intervention & surface equipment must allow:

• Lowering and retrieval of the tool string to the (downhole) work location & its subsequent retrieval.

• Monitoring of tool position & cable tension.

• Equipment to position lubricator & tool string vertically above well & lower through Xmas tree & into the tubing

• The ability to insert tool string into live well & prevent well fluid from escaping into the environment

• A blowout preventor capable of sealing the annulus around the wire & cutting, if necessary, the wireline


Surface Wireline Equipment mounted

on a Xmas Tree

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Surface Wireline Equipment

The wireline is wound onto a reel on a self contained skid with independent power supply for drum rotation &

measurement of cable length & tension


Surface Monitoring Equipment

The wireline operator must know the tool string’s depth in the well & the tension on the cable

• Length of cable inserted in the well gives the approximate depth of the tool string

• This length is measured by holding the cable against an odometer (a wheel with a device that counts the number of rotations) as the tool string is lowered into the well

Also:• The cable tension is continuously monitored to ensure

that the breaking strength of the cable is not exceeded

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Monitoring Cable Tension

The cable tension will:• Increase as the tool string is lowered into the well due

to the increasing weight of the wire &

• Reduceduring recovery of the tool string from the well

• Reduce (rapidly) when it does not easily fall down the well due to increasing friction or a downhole restriction

• Reduce as the tool string is lowered through a restriction in the tubing string; giving an indication of tool position

• Increase (rapidly) if the tool string is "caught" by a downhole restriction during recovery of the wireline


Example Completions

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Single Zone (no tubing movement)

• VAM tubing with anchor seal assembly latched into permanent packer.

• The VAM tubing for high pressure gas production (high quality seal)

• Permanent packer & tailpipe are run & set on drillpipe or electric wireline

• No moving seal assembly -tubing stress adjusted when tubing landed


Single Zone (with Locator Seal Assembly)

• Well produced through a

tubing string with moving

seal assembly located inside a

permanent packer

• Two nipples included in the

tailpipe (for gauge placement)

– Upper one: Isolates formation when the tubing is retrieved

– Lower nipple: for installation of pressure gauges

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Single Zone (with ELTSR)

• Completion can produce at high rates (20,000 - 30,000 b/d)

• Large bore tubing minimises pressure drop in the tubing

• Packer and tailpipe set on electric cable or coiled tubing

• Tubing string is latched into the packer with an anchor seal assembly at the base of an Extra LongTubingSeal Receptacle(ELTSR)

• Tubing movement is ~ 5 -15 ft (depends on flow rates & operating temperatures)


MonoboreSingle Zone (with PBR)

• High Flowrate Completion with Polished Bore Receptacle (PBR)

• Monobore: constant diameter from surface to reservoir (for easier access / intervention)

• PBR: moving seal assembly at base of tubing string allows for tubing expansion/contraction

• No nipple for isolation below PBR• Isolate with tailpipe (& nipple)

below PBR or by thru-tubing bridge plug

• Circulation kill using a shear valve in SPM or SSD

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Single Zone (with gas lift)

• Gas lift string with Side Pocket Mandrels

• Gas Lift valves installed in SPMs allows controlled gas entry into tubing from annulus.

• Retrievable packer preferred if frequent mechanical repair expected


Selective Completion(with gas lift)

• Gas lift gas is injected down the short string or

• Selective or commingled production via a single string

• Gas injection via the tubing avoids excessive gas pressures being exerted on the production casing (casing integrity & offshore safety issues)

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Single Zone (with ESP)

• An ESP installation with “Y” tool allows access to the producing zone below the tailpipe e.g. for production logging surveys etc.

• A retrievable hydraulic set packer reduces difficulties pulling the string when replacing the pump


Dual Completion(segregated production)

• Separate production & management of two reservoir zones

• Retrievable upper dual packer

• Long string connects to lower permanent packer via a moving seal

• Tubing equipment is duplicated in both strings e.g. two ScSSSVs, etc.

• Thick walled tubing (“Blast Joints”) mitigates erosion of the long string at the upper zone fluid entry point

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A “Tubingless” Dual completion

• Triple completion also possible

• Tubing repair more difficult than for a conventional well

– possible with extra equipment


Chapter 1: Learning Objectives

1. Selection criteria for:

– Bottom Hole Completion Technique

– Flow Conduit between Reservoir & Surface

2. Describe:

– Completion String Components & their Function

– Multiple Zone Completions

3. Wireline Servicing of Completion Accessories

petroleum production concepts- conventional completions

Documents

hwu msc

completion conceptsd

pt david daviesintroduction

pt david daviesexamples

pt david davieschapter

pt david davies2revised

completion integrity

pt david daviesopen