WELL COMPLETION

EQUIPMENT

Lecture 4

Chemical Corrosion Agents

• H2S

�Weak acid, source of H+

�Very corrosive, especially at low pressure

�Different regions of corrosion with temperature

• CO2

�Weak acid, (must hydrate to become acid)

�Leads to pitting damage

• Chlorides

�Principally sourced from formation and seawater

• Strong acids

�HCL, HCL/HF, Acetic, Formic

• Brines

�Chlorides and zinc are the most damaging

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Material Selection

• Options�Metallurgy - balance strength and corrosion resistance

� Carbon steels – worked required� Alloy steels - Cr, Ni etc.

�Plastic - good corrosion resistance but limited burst�Tubular linings – economic but susceptible to damage�Internal cladding - good for well heads / special areas�Inhibition - economics depend on flowrate and completion

modification requirements • Selection depends upon:

�Anticipated well life�Location and intervention costs�Material costs�Well configuration – particularly if inhibitor injection is used�Uncertainties both present and future – e.g. souring?

3

Materials Recommendations

• For H2S use low yield C-Steel or Stainless

• For CO2 use Chrome

�Cr alloy is 3-6x cost of carbon steel

�Select and need specialized handling

• For H2S/CO2 and Chlorides use Ni-Cr alloy if appropriate

�Ni alloy could be 100x cost of carbon steel

• For injectors

�Consider the use of plastic coated pipe

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Production Tubing

• Design considerations

�Strength

�Metallurgy – corrosion and erosion

�Sealing capacity

�Internal diameter/through bore

�Handling concerns/constraints

• Options

�Thread/coupling type

� API couplings

� Premium couplings

�Integral versus external coupling

�Upset or non-upset

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Tubing Thread/Connector Options

API Threads

• Conventional round or rectangular profile

• STC or LTC – no. of threads per inch• Buttress

� Higher tensile strength

� Easier make up

• Extreme line• Requires dope to seal• Lower tem/pressure rating

� 230oF

� <3000 psi

• Not preferred for gas wells• Made up to specified torque

• Premium Threads

• Creates 360o seal in profile

� Elastomeric ring compression

� Metal to metal shoulder

� Wedge

� Shoulder

� Taper

• More reliable• Does not need dope to seal• May require a lubricant• More expensive• Many different proprietary designs

� Hydril

� VAM

� Fox

• Made up to torque but also turn counter

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Coupling types – External and Integral

• External coupling uses male threads cut into

each pipe end and female; female collar

�Often higher strength

�Larger external OD

• Integral coupling has male and female threads

cut into pipe body at each

�May require upset to assure adequate strength and

thicker residual wall

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Upset in tubular threads

• Upset options

�Non upset

�External

�Internal

• External upset can give greater strength

• Internal upset not desirable or production tubing

�Wireline and through tubing work may be

compromised

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Function of the Wellhead System

• Allow suspension of casing and tubing in the well

• Allow installation of surface barrier

�BOP stack whilst drilling

�X-mas Tree for production/injection

• Allow hydraulic accesses to annuli between tubular systems

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Wellhead Types

• Conventional spooled wellhead

�Most common

�Studded flanges or C-clamp make-up

• Compact spools

�Used primarily where available height or makeup

procedures are issued

• Mud Line Suspension System

�Split locations of main wellhead functions

• Subsea wellheads

�Complex, remote installation, high cost

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Critical areas of the wellhead system

• Seal surfaces and seal system – rings, gaskets etc.

• Landing shoulders

• Flanges faces and ring recesses

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Compact Spool Type Wellhead

• Benefits

�Less height

�Minimal stack manipulation – drill and case last 2

casing strings and suspend production tubing

• Problems

�Less flexible

�Internal sealing is more complex

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Advantages of metal to metal seals

• More resilient to mechanical damage – it can still be easily damaged!

• Higher ratings in terms of pressure and temperature

• Usually chemically more resistant

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SSSV

• Function

�Well closure in event of the loss of the surface barrier

• Options

�Remotely (surface) controlled

�Wireline/CT retrievable

�Tubing retrievable

�Pressure, acoustic or electrically operated

• Sub-surface controlled

�Wireline/CT retrievable

�Ambient valves –actuated by reduced BHP

�Differential valves – actuated by increased flowrate

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How to choose Safety valves?

Design factors for consideration

• Retrieval requirements – type and location of well

• Setting depth

• Pressure

• Temperature

• Tubing and casing dimensions

• Sand in production fluid

• Price

• Reliability data

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SSSV setting depth• Recommendations vary

�RC valves (SC) – shallower set - normally 100-300 ft minimum below land or seabed

�DC valves (SSC) – less restriction – no control line

• In all cases they must be below the depth to which an explosion or fire at surface could cause damage to the valve

• Influenced by

�Pressure drop of flow stream in passing through the valve

�Valve access/retrieval

�Inventory of hydrocarbons in tubing in the event of closure

�Potential for plugging – hydrates, wax, scale etc.

�Erosional conserns

�Cratering/subsidence – gravity, jack-up or fixed platforms

�Integrity/reliability of equipment below the valve

�Control line integrity/ease to installation/response time

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Control Line Protector Clamps

• Protect control lines from damage whilst running the completion

• Support control line weight

• Keep control lines tight to tubing string

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SSSV Installation

• Make up Safety Valve Assembly

• Shop test equipment

• Deck test

• Drill Floor Test

• Run Equipment

• While RIH, monitor Control line Pressure

• Conduct Final Test at Setting Depth

• Make Final check of Control line Pressure

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Dual Control line RC SSSV

• Balances effects of hydrostatic head

• Applications

�Deep set valves

• Problems

�Control line complexity

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Differential Pressure Storm Chokes (SC SSSV)

• Storm chokes close in only when predetermined

conditions are met and do not offer protection until these

conditions are met

• Valves are wireline or coil retrievable

• Storm chokes are NOT considered a preferred

equivalent/alternative to SC SSSV systems

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Production Packers

Purposes• Protect the casing from reservoir

fluids and pressures

• Separation of zones to avoid crossflow

• Subsurface pressure and fluid control

• Artificial lift efficiency – gas lift

Components• Seal assembly• Slips• Cone assembly

• Friction element�Not on permanent or

hydraulic set units

• Setting and releasing mechanism

�Not on permanent units

• Mandrel assembly• Control head or bypass

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Retrievable Packers

• Can act as a bridge plug prior to production

• Connect to tubing via On/Off tool with blanking plug

• Tubing can be landed in tension, compression or neutral

• Slips above and below the elements

• Triple element pack off system

• Pressure up to 10,000 psi

• Fluid bypass needed for pressure equalization

• Retrieved on tubing

• Secondary shear release needed

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Packer setting - considerations

• Obstacles/considerations to successful set

• Burrs on perforations and pipe above packer set point

• Internal profile of tubing wall at setting depth

• Cement behind pipe at packer set point

• General condition of the pipe

• Amount of pressure to be applied above/below

• Amount of weight applied to packer

• Slip design and contact area

• Hardness of casing relative to packer slips

• Debris on the casing wall (also on slip teeth)

• Clearance between packer and casing (casing weight range of packer)

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Recommendations – packer setting

• Drift and crape casing

• Care should be taken to set the packer In well cemented

casing (integrity of cement checked by log)

• Areas in which to avoid setting of packer

• Sidetracks and windows

• Milling areas

• Casing connections

• Previous packer set points

• Areas of corrosion, including cracking and embrittlement

• Areas of wear (above and through doglegs, etc.)

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Circulation Devices

• Options

• SSD – large flow area/less control of flow rate

• SPM with shear valve – more control or rate but limitations on rate – 2-4 bpm

• Ported nipple –creates tubular internal restriction

• Tubing punch – destroys tubing integrity – need to plan for internal straddle or plug tubing

• Considerations

• Circulation rate

• Preparation/delay

• How to affect closure? Reliability

• Need for a back up – contingency?

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Flow coupling

• Important part of life-of-the-well completion planning

• Wall thickness greater than the corresponding tubing to inhibit erosion caused by flow turbulence

• Should be installed above and below landing nipples or other restrictions that may cause turbulent flow

Applications

• Help inhibit erosion caused by flow turbulence• Installed above and below landing nipples, tubing retrievable safety

valves, or any other restriction that may cause turbulent flowBenefits

• Help extend the life of the well completion

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Side Pocket Mandrel

Side Pocket mandrel can be fitted with:

• Dummy

• Gas lift valve

• Injection valve

• Shear valve

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