Updated Lecture 4 Well Completionfluids

Wellhead Completion& Completion Fluids Lecture - 4 ,Y-3

Lecture Outline • Oil/Gas well before and after completion • Completion Productivity • Production packer • Wellhead Completion • Completion Fluids. • Case Study from oil field

Field Oil well before completion

Field Oil well after completion Oil Well After Completion

X-mas Tree

Tubing hanger

Well Head

Hydraulic Control Line Safety Valve

Production Tubing

Reservoir Gas Lift Valve

Packer

Pump Out Plug

Surface and subsurface equipment's in oil well

Perforation

Sump

Field Flowing oil / gas well

Out-flow dependent on the fluid properties, like water cut, gas liquid ratio, and oil gravity. It also depends on the backpressure imposed by the surface facilities.

In-flow Dependent on productivity index and reservoir pressure.

Reservoir energy overcomes all pressures losses through the entire production system

COMPLETION PRODUCTIVITY There are external parameters that limit choice flexibility of tubing size: • Initial reservoir pressure, • Formation breakdown pressure, • Bubble-point pressure, • Reservoir injectivity and productivity, • Oil properties.

COMPLETION PRODUCTIVITY SIZING THE TUBING • The primary function of the tubing is to provide a conduit for transportation of hydrocarbons or injection water.

• Undersizing the tubing is the most common and costly mistake made by many completion designers. • Undersized tubing will limit the amount of production or injection that can be achieved, or result in inefficient artificial lift.

• Oversizing the tubing can also cause liquid hold-up problems and unnecessarily increase equipment costs.

COMPLETION PRODUCTIVITY • From Darcy's semi steady state flow equation, the PI for a well producing 100% oil is

Koh PI  141.2o o [ln( re / rw )  0.75  S ]

bbl/Day/psi

COMPLETION PRODUCTIVITY • It is commonly assumed that production is directly proportional to drawdown. • The constant of proportionality is termed the productivity index, and is commonly denoted as PI or

J 

PR

q  Pwf

What is a production packer? A Packer is a sub-surface device or equipment used to provide a seal between the Tubing and Casing of a well , thus preventing the movement of fluids past this sealing point. Why is a Packer run? Well Control • Well Testing • Casing Protection • Well repair and stimulation • Zonal Isolation • Artificial Lift Types of packers Permanent packer Retrievable packer

Packer fluids • Packer fluids remain between the casing and tubing to prevent collapsing of casing and burst of the production string. • Therefore, a good packer fluid must be stable with time and temperature, non-corrosive, and economical. • The fluid must also be able to be pumped and must not harm packer seals.

Wellhead Completion

Wellhead and Christmas tree • Wellhead and Christmas tree is the main equipment for oil production, water injection and downhole operation. • It is installed on the casing head to seal the annular space between casing and tubing, control wellhead pressure, adjust • well flow rate and transport oil to pipeline.

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Wellheads and Christmas Trees The wellhead consists of three components - casing head - tubing head - Christmas tree The wellhead must be able to withstand pressures of up (1,400 Bar, or about 2,100 psi) or greater. Once the well has been drilled, it is completed to provide an interface with the reservoir rock and a tubular conduit for the well fluids. The surface pressure control is provided by a Christmas tree, which is installed on top of the wellhead, with isolation valves and choke equipment to control the flow of well fluids during production

Installing the Christmas Tree 

A collection of valves called a Christmas tree is installed on the surface at the top of the casing hanger.

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As the well’s production flows up the tubing, it enters the christmas tree.

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So, the production can be controlled by opening or closing valves on the christmas tree.

A wellhead is used during both drilling and production. During drilling, it is used without a Christmas tree while during production it is used in combination with the Christmas tree, to which the wellhead connects

Wellheads and Christmas Trees Components of a Wellhead - Tubing pressure gauge - Wing valve - Flow fitting - Choke

- Christmas tree

- Tubing head - Master valve - Casing valve - Tubing - Casing pressure gauges

- Tubing head

- Production casing - Uppermost casing head

- Intermediate casing

- Casing head - Lowermost casing head

- Surface casing

Christmas Tree Functions • The purposes of the Christmas tree are • To provide the primary method of closing in a well; isolate the well from adjacent wells; • Connect a flowline; provide vertical access for well interventions (slickline, electricline, coiled tubing, etc.) whilst the well is live; • Interface with the tubing hanger; • Connect or interface the tree to the wellhead.

• Safety Valve • The purpose of the Safety valves is to protect people, environment and property from uncontrolled production. • Type of Safety Valve • SSV: Surface Safety Valves: an automatic fail-safe closed valve fitted at the wellhead. • SSSV: Subsurface Safety Valve: a valve installed in the tubing down the well to

What Is Subsurface Equipment? • A production/injection is equipped with many surface and subsurface equipment. • The surface equipment are x-mas tree, wellhead, surface safety valve, etc.

Completion Fluids Completion fluids shall be:Able to assist in well control. Not cause reservoir or environmental damage. Not allow solids to settle on tools during operations. keep the well in the best possible condition during its producing life”.

Functions of Completion Fluids 1) Improve well productivity by reducing damage to the producing zone. 2) It is the fluid placed against the producing formation while conducting perforation. 3) It is the solids-free liquid used to "complete" an oil or gas well. 4) To remove solids from the well 5) To control formation pressures.

Requirements of Completion Fluids

1)The fluid is meant to control a well should down hole without damaging the producing formation or completion components. 2) Completion fluids should be proper density and flow characteristics. 3) The fluid should be chemically compatible with the reservoir formation and fluids, and is typically filtered to a high degree to avoid introducing solids to the near-wellbore area which may cause formation damage.

Characteristics required for completion fluids 1- Specific gravity. 2- Viscosity. 3- Filtration rate. 4- Compatibility. 5- Stability at reservoir temperature. 6-Safety Handling. 7- Cost or price.

Completion Fluids - Selection Criteria 1- Fluid Density Fluid Density Should Not Be Higher Than Needed to Control Formation Pressure. 2- Oil Content Ideally Fluids Should Not Contains Solids to Avoid Formation & Perforation Plugging. 3- Filtrate Characteristics Characteristics of Filtrate Should Be Tailored to Minimize Formation Damage Considering Clay Swelling, Dispersion & Wettability Changes and Emulsion Stabilization.

Completion Fluids Selection Criteria 4- No Corrosion 5- Economics 6- No Formation Damage Related to Solids 7- Complete Solids Removal To be effective, fluid in contact with the formation must not contain any solids larger than 2 micron size.

 What risks attack the Tubing String ? 1.

Corrosion: Corrosion is caused by presence of H2S. Tubing steel will suffer from hydrogen embrittlement in the presence of moisture H2S. The embrittlement process (sometimes called sulfide corrosion cracking) results from the penetration of hydrogen atoms which can migrate into the steel similarly to fine sand passing through a gravel pack.

2.

Errosion: Ve = c / pm 0.5 where: Ve = fluid erosional velocity, ft/sec c = empirical constant (range 80 to 300) Usually c = 125 for intermittent service, or 100 for continuous service pm = gas/liquid mixture density, Ibs/ft3

Steps For Selecting Fluid Type 1- Knowing PR, Get Fluid Density to Control PR. 2- Add 100-200 psi for Safety. 3- Define Viscosity Requirement. 4- Choose Completion Fluid that Meets Above Criteria With No Formation Damage. Fluid Density = (BHP + Overbalance)/ 0.052xDepth in feet ) ppg

Types of Completion Fluids 1- Oil Base Fluids  Crude Oil Availability makes crude oil a common choice where low (8.3 Ib/gal) density is required. Loss of oil to the formation is usually not harmful. Low viscosity crude has limited carrying capacity.  Diesel Oil This is often used where a low density clean fluid is required. 2- Water Base Fluids  Formation Saltwater When available, formation saltwater is a common workover fluid since the cost is low. If it is clean, formation saltwater should be ideal for minimum clay swelling  Seawater or Bay Water Due to availability, it is often used in coastal areas. Again, it frequently contains clays and other fines that cause plugging. Fresh water is often desirable as a basic fluid due to the difficulty of obtaining clean sea or formation water. Desired type and amount of salt is then added.

Types of Completion Fluids 3- Conventional Water-Base Mud Economics and availability sometimes suggest use of water-base mud rather than weighted saltwater where weights above 11.5 Ib/gal are required. Water-base mud should never be used except in zones to be abandoned. 4- Oil-Base or Invert-Emulsion Muds These muds are usually less damaging from the standpoint of clay problems than conventional water base mud's since filtrate is oil and very low filtration rates can be obtained. 5- Foam Foams can be used for certain workover operations (very low BHP) such as washing out sand, drilling in or deepening. Depending on the ratio of air to foam water circulated, flow gradients as low as 0.1 to 0.2 psi/ft are possible. Foam is a mechanical mixture of air or gas dispersed in clean fresh water or field brine containing a small amount of surfactant.

Completion Fluids - Practical Application  Formation Damage

Laboratory core flow tests apparently do not show unfavorable fluid/rock interactions with heavy brines. Incompatibility with formation water should be carefully observed specially if formation water contains significant sulfate or bicarbonate.  Cost Heavy brines are very expensive. A 15.0 Ib/ gal CaCl2CaBr2 brine costs about 25 times more than a 10.0 Ib/gal CaCl2 "new" brine. Fluid Recovery and reuse may minimize cost.

Completion Fluids - Practical Application  Viscosity and Fluid Loss Control

A number of additives are available to provide "viscosity," thereby increasing the lifting, carrying, and suspending capacity of the fluid. Ideally, fluid loss control should be obtained strictly by a bridging mechanism at the face of the formation. This can be done effectively by use of properly sized particles. Particles larger than one-half the pore size should bridge at the pore entrance.

Completion Fluids - Practical Application  Fluid Loss Control Due to un-regained permeability loss, most currently available viscosity builders should not be used without proper bridging particles to prevent movement of the viscosity colloids into the formation pore system. Bridging particles must meet two criteria:  Form a stable, low-permeability bridge quickly.  Be removable by degradation or backflow. 

Calcium Carbonate This material is available in several size ranges  Oil Soluble Resins These are available in graded size ranges needed for effective bridging action.  Graded Rock Salt Where saturated salt fluids are used, graded rock salt with HEC can provide effective fluid loss control.