Completion Design

COMPLETION DESIGN

INTRODUCTION In simple terms, the term 'well completion' refers to the methods by which a newly drilled well can be finalized so that reservoir fluids can be produced to surface production facilities efficiently and safely. In general, the process of completing a well includes the following: • A method of providing satisfactory communication between the reservoir and the borehole. • The design of the tubular (casing and tubing) which will be installed in the well. • An appropriate method of raising reservoir fluids to the surface.

• The design, and the installation in the well of the various components used to allow efficient production, pressure integrity testing, emergency containment of reservoir fluids, reservoir monitoring, barrier placement, well maintenance and well kill. • The installation of safety devices and equipment which will automatically shut a well in the event of a disaster. In general, a well is the communication link between the surface and the reservoir and it represents a large percentage of the expenditure in the development of an oil or gas field.

DESIGN CONSIDERATIONS Before a production well is drilled, a great deal of planning must be undertaken to ensure that the design of the completion is the best possible. A number of factors must be taken into consideration during this planning stage, which can broadly be split into reservoir considerations and mechanical considerations.

RESERVOIR CONSIDERATIONS: • Producing Rate • Multiple Reservoirs • Reservoir Drive Mechanism • Secondary Recovery Requirements • Stimulation • Sand Control • Artificial Lift • Workover Requirements.

MECHANICAL CONSIDERATIONS: • Functional Requirements • Operating Conditions • Component Design • Component Reliability • Safety.

PERFORATING

History Of Perforation In Brief

• Prior to the early 1930's , casing could be perforated in place by mechanical perforators. These tools consisted of either a single blade or wheel-type knife which could be opened at the desired level to cut vertical slots in the casing. • Bullet perforating equipment was developed in the early 1930's and has been in continuous and widespread use since that time.

The major disadvantage with this method were that :1. the bullet remained in the perforation tunnel, 2. penetration was not very good, 3. some casings could not be perforated effectively.

• After World War II the Monroe , or shaped – charge , principle was adapted to oil well work , and the resulting practice is now commonly referred to as jet perforating. The principle of the shaped charge was developed during World War II for armor piercing shells used in bazookas to destroy tanks. This new technology allowed the oil producers to have some control over the perforating design (penetration and entry hole size) to optimize productivity.

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 optimize perforating efficiency, it is not only 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, •perforating orientation.

SHAPED CHARGE PERFORATING

• As mentioned earlier, wells today are generally cased and cemented, so in order to allow the well to produce hydrocarbons, openings must be made through the casing and cement. These openings (or perforations) are created using explosive bullets, known as “shaped charges”, using the same principle as the military‟s armor piercing rounds.

Stages of a shaped charge during perforating

Unfired Shaped charge

Charge Detonates Liner Begins To Collapse

High pressure jet forms Pressure wave travels at 8000 ft/sec and 7000,000 psi

Jet becomes more developed pressure causes jet velocity to incease to 23,000 ft/sec Jet elongates Since the back of the jet travels at a slower velocity ( 1,000 ft/sec)

The guns containing the shaped charges can be run into the well using wireline, coiled tubing, drillpipe or tubing.

Gun Types and Perforation Methods There are three basic perforating gun types: • Retrievable hollow carrier gun • Non-Retrievable or Expendable gun • Semi-Expendable gun. 1- The retrievable hollow gun carrier consists of a steel tube into which a shaped charge is secured - the gun tube is sealed against hydrostatic pressure, The charge is surrounded by air at atmospheric pressure. When the charge fires, the explosive force slightly expand the carrier wall but the gun and the debris within the gun are fully retrieved from the well.

2- The non-retrievable or expendable gun consists of individually sealed cases made of a frangible material e.g. aluminum, ceramic or cast iron; Refer to Figure Sb. The shaped charge is contained within the case and when detonated, blasts the case into small pieces. Debris remains in the well.

3- semi-expendable guns the charges are secured on a retrievable wire carrier or metal bar., This reduces the debris left in the well and generally increases the ruggedness of the gun.

Perforation Methods There are four main types of perforating guns: 1. 2. 3. 4.

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.

•Through-Tubing Hollow Carrier Guns

These are smaller versions of casing guns which can be run through tubing, hence have lower charge sizes and, therefore performance, than all other guns. They only offer 0o or 180o phasing with a max. of 4 (spf) on the 21/8” OD gun and 6spf on the 27/8” OD gun. Due to the stand-off from the casing which these guns may have, they are usually fitted with decentralizing/orientation devices.

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 through tubing carriers guns, however they also cause more debris, casing damage and have less mechanical and electrical reliability. They also provide 0o or 180o 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

•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.

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.

The advantages of TCP systems are: • Large intervals can be perforated at one time • Easy to perforate in deviated wells • Large gun sizes can be used with high shot densities • Perforating may be carried out in under-balanced conditions • Safest method to perforate.

Operations • When the decision is made to perforate, several questions need to be answered to ensure maximum flow efficiency from the perforated zone. Some of those questions are; •shot density,

•phase angle, •penetration length,

•penetration diameter.

• Shot Density Computer programs are used to determine the number of shots per foot (spf) or shots per meter (spm) required for the reservoir (using the anticipated production rate of the well). Regardless of the number of shots, the clean up efficiency mustdensity be keptininhomogeneous, mind. Shot isotropic formations should be a minimum of 8 spf 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.

•Phase Angle The phase angle or “phasing "is the direction in which the shaped charges are fired relative to the other shots in the gun. Common phase angles are 45o, 60o, 90o and 120o. This phasing becomes very important when perforating horizontal boreholes where you want to perforate only the low side of the hole or where there are other tubing strings in the well and the perforations have to be performed around the other completion strings.

Phase angles for perforating guns

•Penetration Length The actual depth of penetration has a great effect on production performance, therefore it is usually necessary to obtain the greatest penetration possible. The length of the perforation is difficult to determine, and tunnel length is generally provided by the manufactures, based on gum size, test material (i.e. concrete or sandstone, etc.) and shot type (i.e. Gravel Pack Charge or Deep Penetrating Charge). Generally, the deep penetration charge will give a tunnel between 1 and 2 feet in length, while the gravel pack shot will only be about 8 inches in length.

•Penetration Diameter Gravel pack charges produce large diameter holes (around 1inch), while the deep penetrating charges will produce an opening between 0.5 and 0.75 inches in diameter.

Wellbore Conditions While Perforating • Overbalanced

• Underbalanced

Overbalanced Perforating

Casing Cement Perforating gun

Completion fluid in wellbore Perforations can be plugged with debris in wellbore

Pressure controls well during completion

Oil or gas reservoir

Pres< phyd > pres

Underbalanced Perforating

Casing Cement Perforating gun Well will be ‘live’ and need control after perforating

Completion fluid in wellbore Perforations will be clean from surge in wellbore

Pres> phyd < pres

Oil or gas reservoir

CLASSIFICATION OF COMPLETIONS

Completion designs may be classified as described below: Reservoir/Wellbore Interface

In the absence of formation damage, this determines the rate at which well fluid is transferred from the formation to the wellbore. The types of completion involved here are: • Open hole completions • Uncemented liner completions • Perforated liner completions • Perforated casing.

Mode of Production This relates to the manner that well fluid is transferred from the wellbore at the formation depth to the surface, i.e.: • Flowing • Artificial lift.

Number of Zones Completed This effectively governs the volume of hydrocarbons recoverable from a single borehole: • Single • Multiple.

CLASSIFICATION-BY RESERVOIR/WELLBORE INTERFACE 1- Open Hole Completions In this type of completion the casing is set in place and cemented above the productive formation(s). Further drilling extends the wellbore into the reservoir(s) and the extended hole is not cased;

Advantages of open hole completions are: • The entire pay zone is open to the wellbore • Perforating cost is eliminated • Log interpretation is not critical since the entire interval is open to flow • The maximum wellbore diameter is across the pay zone(s) reducing drawdown • The well can easily be deepened • Is easily converted to liner or perforated casing completion • Minimal formation damage is caused by cementing.

Disadvantages of open hole completions are: • The formation may be damaged during the drilling process • Excessive gas or water production is difficult to control because the entire interval is open to flow • The casing is set before the pay zone(s) are drilled and logged • Separate zones within the completion are difficult to selectively fracture or acidize • Requires frequent clean out if producing formations are not consolidated. Limitations of open hole completions are: • Unsuitable to produce pay zones with incompatible fluid properties and pressures • Mainly limited to hard Limestone formations.

2- Uncemented Liner Completions In some formations hydrocarbons exist in regions where the rock particles are not bonded together and sand will move towards the wellbore as well fluids are produced, this formation is usually referred to as being 'Unconsolidated'. The use of uncemented; liners (slotted or screened) act as a strainer stopping the flow of sand. Liners are hung off from the foot of the previous production casing and are usually sealed off within to direct well flow through the liner bore.

Advantages of uncemented liner completions are: • Entire pay zone is open to the wellbore • No perforating cost • Log interpretation is not critical • Adaptable to special sand control methods • No clean out problems • Wire wrapped screens can be placed later. Disadvantages of uncemented liner completions are: • The formation may be damaged during the drilling process • Excessive water or gas is difficult to control • Casing is set before pay zones are drilled and logged • Selective stimulation is not possible.

Various examples of uncemented liner operations implementing sand control are as follows:

Slotted Liner

Slot widths depend on the size of the sand grains in the formation and are typically from 0.01 ins. wide upwards,

Wire Wrapped Screen A liner is drilled with 3/8 ins to l/Z ins. (9.53 - 12.7 mm) holes along its length and is then lightly wrapped with a special V-shaped wire

Pre-packed Screen A pre-packed screen is constructed of an outer and inner wrapped screens with resin coated gravel placed between the screens. This gives a performance better than a wire wrapped screen but less that an open hole gravel pack,

External Gravel Pack In this type of completion, the open hole is usually enlarged to about twice its drilled diameter into which a screened liner is installed. Gravel of a selected size, calculated to prevent formation sand movement, is placed between the outside of the screen and the formation by using special gravel pack running equipment,

3- Perforated Cemented Liner Completions In perforated cemented liner completion designs, the casing is set above the producing zone(s) and the pay section(s) drilled. Liner casing is then cemented in place that is subsequently punctured (perforated) by bullet-shaped explosive charges. The reason for requiring the installation of a liner is generally drilling related unless a high rate liner or monobore completion design is to be used.

Advantages of perforated liner completions are: • Operations are safer during well completion operations • The effect of formation damage is minimised • Excessive water or gas production may be controlled or eliminated • The zones can be selectively stimulated • The liner helps impede sand influx • The controlled bore size makes it easier to plan for completion. Disadvantages of perforated liner completions are: • The wellbore diameter through the pay zone(s) is restricted • Log interpretation is critical • Liner cementation is more difficult to obtain than casing cementation • Perforating, cementing and rig time incurs additional costs.

4- Perforated Cemented Casing Completions In a perforated cemented casing completion, sometimes referred to as the 'set through‟ completion, the hole is drilled through the formation(s) of interest and production casing is run and cemented across the section. Again, this requires that perforations be made through the casing and cement to reach the zone(s) of interest and allow well fluids to flow into the wellbore.

Methods of completing a well in perforated cemented casing completions are: Standard Perforated Cemented Casing completion.

Internal Gravel Packs This is where the production casing is cemented. Perforation of the producing interval(s) is then performed and the perforations cleaned out. A screen is run and gravel is pumped into the casing/screen annulus and the perforation tunnels.

CLASSIFICATION-BY MODE OF PRODUCTION Tubing less Completions Casing flow completions are a particularly low-cost completion method used in marginal flow conditions such as low rate gas wells,

NOTE: Most operators do not normally use casing Dow completions, primarily because the production casing is exposed to well pressure and/or corrosive fluids. Tubingless completions are potentially hazardous especially in offshore installations as there is an increased risk of collision damage with no facility to install down hole safety valve systems. The use of casing flow production methods are discouraged both offshore and onshore.

Tubing Flow Completions Tubing flow completions utilize the tubing to convey well fluids to surface. Flow rate potential is much lower in tubing flow than in unrestricted casing flow completions. As well as for production, the tubing string can be utilized as a kill string or for the injection of chemicals.

Tubing strings may also accommodate gas lift valves that essentially 'gas assists' formation liquids to surface; these valves would be installed if formation pressure diminished considerably and natural drive ceased.

The completion engineer should consider the following factors for tubing/packer type completion installations: • Simplification of the completion for future well servicing operations (i.e. wireline,coiled tubing, snubbing etc.) • Optimum tubing size for maximum long term flow rate • Future artificial lift needs • Bottom hole pressure and temperature gauge survey hangoff system

• Seal movement device to accommodate tubing elongation or contraction • Availability of down hole circulating device

• Requirements for down hole corrosion inhibitor injection • Requirements for down hole hydrate inhibitors

• Tubing-conveyed perforating (TCP) guns and/or through tubing guns for underbalanced perforating • Fluids to be used i.e. drilling muds, completion fluid, wellbore fluid • Well killing.

By far the most common methods of completing a well is to use a single tubing string/packer system where the packer is installed in the production casing to offer casing protection, subsurface well control, and an anchor for the tubing.

Other equipment commonly installed in tubing string completions to facilitate safer production may be: Wireline Nipples

Permits the installation of flow controls or plugs.

Tubing Retrievable Safety Valve

For emergency well shut-in.

Safety Valve Landing Permits the installation of a Surface Controlled Nipple Subsurface Safety Valve (SCSSV)for emergency shut-in. Flow Couplings

Absorbs erosion caused by turbulence and abrasion.

Circulating Device

Fitted above the packer for circulating purposes

Tubing Seal Device

To allow tubing movement.

Artificial Lift When a reservoir's natural pressure is insufficient to deliver liquids to surface production facilities, artificial lift methods are necessary to enhance recovery.

There are various artificial lift completion methods and the key completion considerations are: Rod Pump Lift These pumps consist of a cylinder and piston with an intake and discharge valve. Vertical reciprocation of the rod will displace well fluid into the tubing; These are utilized in low to moderate wells which deliver less than 4,500 BPD (318m3 / day). Key considerations are: • The annulus is open to gas flow • A tubing anchor may be required to reduce rod and tubing wear/ stress • The pump diameter must be of sufficient size • The rods must be properly sized.

Hydraulic Pump Lift Hydraulic pump lift is utilized in crooked holes, for heavy oils and variable production conditions that cause problems for conventional rod pumping. Key considerations for the use of hydraulic pumps are

• The number of flow conduits (production and power) •Pressure losses in the power and return lines •Whether produced liquid can return up the casing •Lubricator access to pump-in jet or piston units •The large casing size required for turbine units •The power fluid/oil separation facilities required •The higher initial costs.

Plunger Lift The plunger lift system, is a low rate lift system in which annulus gas energy is used to drive a plunger carrying a small slug of liquid up the tubing when the well is opened at surface. Subsequent closing of the well allows the plunger to fall back to bottom. Plunger lift is useful for de-watering low rate gas wells. Key considerations are: • The tubing must be drifted prior to installation • The annulus is open to store lift gas • A nipple/ collar stop must be installed to support a catcher and shock absorber.

Gas Lift Gas lift supplements the flow process by the addition of compressed gas which lightens the liquid head, reduces the liquid viscosity, reduces friction and supplies potential energy in the form of gas expansion, Continuous gas lift is used to lift liquid from reservoirs that have a high productivity index (PI) and a high bottom hole pressure BHP. Intermittent lift is used in reservoirs that exhibit low PI/low BHP, low PI/high BHP, or high PI/low BHP. Liquid production can range from 300 - 4,000 bbls/ day (48 - 636 m3/ day) through normal size tubing strings. Casing flow can lift up to 25,000 bbls/ day (3,975m3/ day). Key considerations for gas lift are: • Tubing size • The need for a packer • Setting depths for gas-lift valves.

CLASSIFICATION BY NUMBER OF ZONES COMPLETED Single Zone Completions

Flowing wells that are equipped with a single tubing string are usually completed with a packer. Single zone completions include the downhole co-mingling of production from several intervals within a pay zone.

Multiple Zone Completions When a well has multiple pay zones a decision must be made either to:

• Produce the zones individually, one after the other, through a single tubing string and the annulus • Complete the well with multiple tubing strings and produce several zones simultaneously • Co-mingle several zones in a single completion

• Produce only one zone from that well and drill additional wells to produce from the other pay zones.

The advantages of multiple zone completions: • Some individual zone production • Reduced well cost.

Disadvantages of multiple zone completions are: • Production casing is exposed to well pressure and corrosive fluids • Tubing can be stuck in place due to solids settling from the upper zone • The lower zone must be killed or plugged off before servicing can be done on the upper zone • The lower zone must be plugged off to measure any flowing bottom hole temperature associated with the upper zone.

Multi-zone completions not only provide the separation of various zones but also the separation of individual pay sections within a thick pay zone.

HORIZONTAL COMPLETIONS 'Multi-zonal' wells are prime candidates for horizontal completions as are formations that have naturally fractured networks from which large production increases can be expected,

COMPLETION COMPONENTS

COMPLETION COMPONENTS 1. RE-ENTRY GUIDE 2. LANDING NIPPLE 3. TUBING PROTECTION JOINT 4. PERFORATED JOINT 5. SLIDING SIDE DOOR 6. FLOW COUPLINGS 7. SIDE POCKET MANDRELS 8. SUB-SURFACE SAFETY VALVES (SSSVS) 9. ANNULUS SAFETY VALVES (ASVS) 10.DOWNHOLE CHOKE ASSEMBLIES 11.TUBING HANGER 12.XMAS TREE 13.EXPANSION JOINTS 14. Production Packer

1- RE-ENTRY GUIDE A re-entry guide generally takes one of two forms:

A. Bell Guide The Bell Guide; Figure 1, has a 45° lead in taper to allow easy re-entry into the tubing of well intervention tool strings (i.e., wire line or coiled tubing). This guide is commonly used in completions where the end of the tubing string does not need to bypass the top of a liner hanger.

B. Mule Shoe The Mule Shoe Guide; Figure 1, is essentially the same as the Bell Guide with the exception of a large 45° shoulder. Should the tubing land on a liner lip while running the completion in the well, the large 45° shoulder should orientate onto the liner lip and kick the tubing into the liner.

2- LANDING NIPPLE

A Landing Nipple is a short tubular device with an internally machined profile which can accommodate and secure a locking device called a lock mandrel run usually using wireline well intervention equipment. The landing nipple also provides a pressure seal against the internal bore of the nipple and the outer surface of the locking mandrel.

Common uses for landing nipples are as follows: • Installation points for setting plugs for pressure testing, setting hydraulic-set packers or isolating zones • Installation point for a sub-surface safety valve (SSSV)

• Installation point for a downhole regulator or choke • Installation point for bottomhole pressure and temperature gauges.

NOTE: In highly deviated wells, it may not be possible to use Landing Nipples at inclinations greater than 70°. Wireline operators commonly use Landing Nipples for depth references. Although Their Primary Function is as locating devices.

The plugs that may be installed in Landing Nipples are: • Plug with shear disc (pump-open) • Plug with equalizing valve • Plug with non-return valve.

and the choice of plug depends on the pressure control required and the chances of retrieval.

All of the landing nipples have at least two points in common

1/ locking grove: allowing the tool to be mechanically locked in the landing nipple

2/ a seal bore where seal is made between landing nipple and the tools

There are to main types of landing nipple 1- full bore simple landing nipple :It contains: * Full bore simple called full bore * Full bore selective called selective * Full bore top no go called top no-go

2- bottom no go landing nipple :

Full Bore Simple : Have only got a locking grove and seal bore Maximum mandrel diameter is less then landing nipple nominal diameter Applications 1- Single and dual completions Benefits 1- Maximum reliability and simplicity of locating

Full Bore Selective : Selection key on the mandrel first into the selection profile of the landing nipple Maximum mandrel diameter less than landing nipple nominal diameter

Applications 1- Single and dual completions

Full Bore Top No Go :

The upper part of these landing nipples is over size in comparison with the seal bore So the mandrel with no-go ring of a diameter larger than the landing nipple nominal diameter. The downward locking by no-go can be released using downward jarring.

Bottom No Go :

It can include a system of locking dogs that lock the mandrel upward. During the setting operation the tool must be seated gently on its landing nipple. The completion equipment may then have to be pulled out in order to retrieve them. Manufactures called them bottom no-go.

3- TUBING PROTECTION JOINT

This is a joint of tubing included for the specific purpose of protecting bottom hole pressure and temperature gauges from excessive vibration while installed in the landing nipple directly above.

4- PERFORATED JOINT A Perforated Joint, may be incorporated in the completion string for the purpose of providing bypass flow if bottom hole pressure and temperature gauges are used for reservoir monitoring. The design criteria for a Perforated Joint is that the total cross-sectional area of the holes should be at least equivalent to the cross sectional area corresponding to internal diameter of the tubing.

5- SLIDING SIDE DOOR

A Sliding Side Door (SSD) or Sliding Sleeve, allows communication between the tubing and the annulus. Sliding Side Doors consist of two concentric sleeves, each with slots or holes. The inner sleeve can be moved with well intervention tools, usually wireline, to align the openings to provide a communication path for the circulation of fluids.

Sliding Side Doors are used for the following purposes: • To circulate a less dense fluid into the tubing prior to production • To circulate appropriate kill fluid into the well prior to workover • As a production devices in a multi-zone completion • As a contingency should tubing/tailpipe plugging occur • As a contingency to equalize pressure across a deep set plug after pressure integrity testing • To assist in the removal of hydrocarbons below packers.

NOTE: As with all communication devices, the differential pressure across SSDs should be known prior to opening. NOTE:

In some areas, the sealing systems between the concentric sleeves are incompatible with the produced fluids and hence alternative methods of producing tubing-to-annulus communication is used (e.g. Side Pocket Mandrel, Tubing Perforating).

6- FLOW COUPLINGS Flow Couplings are used in many completions above and/ or below a completion component where turbulence may exist to prevent loss of tubing string integrity and mechanical strength due to internal erosion directly above and/or below the component. Turbulence may be caused by the profiles internal to a component.

NOTE:

In multi-zone completions, Blast Joints are commonly used to prevent loss of tubing string integrity due to external erosion resulting from the jetting actions directly opposite producing formations.

7- SIDE POCKET MANDRELS

A Side Pocket Mandrel (SPM), along with its through bore, contains an offset pocket which is ported to the annulus. Various valves can be installed/retrieved into/ from the side pocket by wire line methods to facilitate annulus-to-tubing communication.

Side pocket valves, which provide a seal above and below the communication ports, include: Gas Lift Valves when installed in the SPM, the valve responds to the pressure of gas injected into the annulus by opening and allowing gas injection into the tubing. In a gas lift system, the lowest SPM is that used for gas injection into the tubing and the upper SPMs are those used to unload the annulus of completion fluid down to the point of gas injection. Chemical Injection Valves these allow injection of chemicals (e.g. corrosion inhibitors) into the tubing. They are opened by pressure on the annulus side.

Circulation Valves

these are used to circulate fluids from the annulus to the tubing without damaging the pocket. Equalization Valves are isolation and pressure equalization devices that prevent communication between the tubing and the annulus, and can provide an equalization facility by initially removing a prong from the valve.

Differential Kill Valves these are used to provide a means of communication between the annulus and the tubing by the application of annulus pressure. An SPM with a differential valve installed provides the same function as a Sliding Side Door. Dummy Valves these are solely isolation devices that prevent ommunication between the tubing and the annulus.

NOTE: An SPM may be used as a circulation device in preference to an SSD as side pocket valves may be retrieved for repair and/or seal replacement.

8- SUB-SURFACE SAFETY VALVES (SSSVS)

The purpose of an SSSV is to shut off flow from a well in the event of a potentially catastrophic situation occurring. These situations include serious damage to the wellhead, failure of surface equipment, and fire at surface. Different operating companies have differing philosophies on the inclusion an SSSV .For example, in an offshore well, at least one SSSV is placed in every well at a depth which varies from 200 ft to 2,000 ft below the sea bed. The depth at which an SSSV is installed in a completion is dependent on well environment (onshore, offshore), production characteristics (wax or hydrate deposition depth), and the characteristics of the safety valve (maximum failsafe setting depth).

SSSVs can be divide into type groups according to their method of operation: A. Direct Controlled Safety Valves

These are designed to shut in the well when changes occur in the flowing conditions at the depth of the valve, that is, when the flowing condition exceed a pre-determined rate or when the pressure in the tubing at the depth of the valve falls below a pre-determined value. Such valves are often called 'storm chokes'. These valves are termed Sub-Surface Controlled Sub- Surface Safety Valves (SSCSVs).

B. Remote Controlled Safety Valves

These are independent of changes in well conditions and are actuated open usually by hydraulic pressure from surface via a control line to the depth of the safety valve. Loss of hydraulic pressure will result in closure of the valve. A number of monitoring pilots or sensing devices can be linked to the safety system, each pilot capable of causing the valve to close if it senses a potentially dangerous situation. These valves are termed Surface Controlled Sub- Surface Safety Valves (SCSSVs).

An SCSSVs run on wireline is called a wireline retrievable safety valve (WRSV)and is installed in a special safety valve landing nipple (SVLN) which is made up as part of the completion string. A control line external to the tubing provides hydraulic pressure to actuate the valve open. The main advantage of utilizing a WRSV is that

it can be economically retrieved for inspection. A primary disadvantage of a WRSV is related to

its restricted bore which does present a restriction to flow, and can cause hydrate or paraffin plugging if the appropriate conditions exist

An SCSSVs run as part of the tubing string is called a tubing retrievable safety valve (TRSV). Again, a control line external to the tubing provides hydraulic pressure to actuate the valve open. The main advantage of a TRSV is that unrestricted flow is provided by its full-bore design which does not contribute to hydrate or paraffin plugging problems. The main disadvantage is that in the event of a critical failure of the valve, the completion string must be pulled and this can be an extremely expensive operation. This disadvantage has been partially overcome by the development of lock open tools for the TRSV and the provision for a surface controlled wireline retrievable insert valve to be installed in the body of the TRSV.

9- ANNULUS SAFETY VALVES (ASVS) In gas lift systems where a large amounts of pressurized gas exists in the tubing-casing annulus, Annulus Safety Valves may be incorporated to contain this gas inventory in the annulus in the event that the wellhead becomes damaged. 10- DOWNHOLE CHOKE ASSEMBLIES

In certain circumstances it is desirable to control a well with a down hole choke in preference to a surface choke as is normal practice. This may be required for two main reasons, 1. For the control of hydrate formation 2. For the control of wax deposition in the tubing string, usually found between surface and a depth of 2,000 ft

If the choke is to be installed for the control of hydrates, a downhole choke would be installed as deep as possible in the well ,and would have the following advantages/ disadvantages Advantages • Surface operations are safer due to the reduced surface pressure during flow periods. • The pressure and temperature drop are taken in a hotter environment, reducing the likelihood of hydrate formation. • Methanol injection should not be necessary. This avoids potential handling problems at surface as methanol is a hazardous material.

Disadvantages • The cost of a downhole choke is greater than an equivalent surface choke. •The flowing pressure immediately downstream of the downhole choke must be calculated to ensure critical flowing conditions. •If any change in the flow rates are required, the choke must be removed from the well using wireline, and a replacement installed. •An adjustable choke must be installed at surface to control the well when bringing the well back into production. The well would be brought on gradually with the adjustable choke until the well is being controlled by the downhole choke. The adjustable surface choke would then be opened fully.

If the installation of a downhole choke is for the control of wax deposition it may be installed immediately below the wax formation depth , And would have the following advantages / disadvantages Advantages • When the downhole choke is installed wax deposition is eliminated for two reasons. Firstly, the fluid flow downstream of the choke is turbulent and secondly the velocity is greater. • Expensive slickline wax cutting operations are not required. • Wax inhibitors are generally xylene based, are a known cancer agent, and are expensive. Disadvantages • The disadvantages are the same as listed above for hydrate control.

Down Hole Choke installation

11- TUBING HANGER The Tubing Hanger is a completion component which sits inside the Tubing Head Spool and provides the following functions: • Suspends the tubing • Provides a seal between the tubing and the tubing head spool • Installation point for barrier protection. The Tubing Head Spool provides the following functions: • Provides a facility to lock the tubing hanger in place • Provides a facility for fluid access to the 'A' annulus • Provides an appropriate base for the completion Xmas Tree.

12- XMASTREE An Xmas Tree is an assembly of valves, all with specific functions, used to control flow from the well and to provide well intervention access for well maintenance or reservoir monitoring. A Xmas Tree may be a composite collection of valves or, more commonly nowadays, constructed from a single block. The solid block enables the unit to be smaller and eliminates the danger of leakage from

flanges. Typically, from bottom to top, an Xmas Tree will contain the following valves: Lower Master Gate Valve

Manually operated and used as a last resort to shut in a well.

Upper Master Gate Valve

Usually hydraulically operated and also used to shut in a well

Flow Wing Valve

Manually operated to permit the passage of hydrocarbons to the production choke.

Kill Wing Valve

Manually operated to permit entry of kill fluid to into the tubing.

Swab Valve

Manually operated and used to allow vertical access into the tubing for well intervention work.

13- EXPANSION JOINTS

These are telescoping devices, usually used in a completion string above a retrievable packer to compensate for tubing movement and possibly to prevent premature release of the packer from the well.

14- PRODUCTION PACKERS • A production packer may be defined as a sub-surface component used to provide a seal between the casing and the tubing in a well to prevent the vertical movement of fluids past the sealing point, allowing fluids from a reservoir to be produced to surface facilities through the production tubing. •In general, packers are constructed of hardened slips which are forced to bite into the casing wall to prevent upward or downward movement while a system of rubberized elements contact the casing wall to effect a seal.

•There are three basic types used in completion designs: 1. Permanent 2. Retrievable 3. Permanent Retrievable.

1- 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.

• 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. •I n relatively mild well conditions. • Retrievable packer setting mechanisms are by: · Tubing tension · Tubing compression · Hydraulic pressure · Tubing rotation.

2- 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 temperatures in excess of 300oF 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.

NOTE: In general, permanent production packers can withstand much greater differential pressures than the equivalent retrievable packer.

3- 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.

Completion Design Example 1 Consider the casing schematic in Section 1 Figure 1. The objective is to design a completion string for this well with following basic functional requirements: • To provide optimum flowing conditions • To protect the casing from well fluids • To contain reservoir pressure in an emergency • To enable downhole chemical injection • To enable the well to be put in a safe condition prior to removing the production conduit (i.e.. to be killed) • To enable routine downhole operations.

The completion design of Figure 1 also addresses the other functional requirements of: • Suspension the tubing • Compensation for expansion or contraction of the tubing

• Internal erosion of the tubing • Protection of the reservoir during well kill operations • Pumping operations for well kill • Well intervention operations out of the lower end of the tubing • Pressure integrity testing • Reservoir monitoring • Installation points for well barriers.

The component selection for this completion is shown in Table 1.

Completion Design Example 2

Figure 2 shows another example of a Single Zone Single String Completion that illustrates additional functional requirements.

The component selection for this completion is shown in Table 2:

COMPLETION AND WORKOVER FLUID

By definition a completion or work over fluid is a fluid placed against the producing formation conducting such operations as Well killing, cleaning out, and drilling in plugging back, controlling sand, or Perforating. Basic completion and work over fluid functions are to

1.facilitate movement of treating fluids to a particular point down hole 2. To remove solids from the well and 3.To control formation pressures. Required fluid properties vary depending on the operation but the possibility of formation damage should always be an important concern.

These points should be considered in selecting a workover or completion fluid: 1. Fluid Density – Fluid density should be no higher than needed to control formation pressure. 2. Solids Content – Ideally, the fluid should contain no solids to avoid formation and perforation plugging, particles up to 5 micron size caused significantly more plugging than particles less than 2 micron size in both cases plugging occurred within the core channels. 3. Filtrate Characteristics – Characteristics of the filtrate should be tailored to minimize formation damage Considering swelling of dispersion of clays, wettability changes, and emulsion stabilization.

4. Fluid Loss – Fluid loss characteristics may have to be tailored to prevent loss of excessive quantities of fluid to the formation, or to permit application of "hydraulic stress" to an unconsolidated sand formation. 5. Viscosity-Related Characteristics – Viscosity-Related Characteristics, such as yield point, plastic viscosity, and gel strength. May have to be tailored to provide fluid lifting capacity required to bring sand or cuttings to the surface at reasonable circulating rates. Lab tests show that many viscosity builders cause permanent reduction in permeability. This can be minimized by careful polymer selection along with adequate fluid Joss control to limit invasion.

6. Corrosion Products – The fluid should be chemically stable so that reaction of free oxygen with tubular steels is minimized, and that iron in solution is sequestered and not permitted to precipitate in the formation. A reasonable upper limit on corrosivity for a completion or workover fluid is 0.05 Ib/ft2. (About 1 mil) per workover. For a packer fluid, the corrosivity target should be about 1 mil per year, but 5 mils per year are considered to be an acceptable upper limit. 7. Mechanical Considerations – Rig equipment available for mixing, storage, solids removal, and circulating is often a factor in fluid selection 8. Economics – The most economical fluid commensurate with the well's susceptibili to damage should

Formation DAMAGE RELATED TO SOLIDS There are two basic approaches to minimize formation damage due to solids entrained in the completion fluid Complete Solids Removal To be effective Fluid in contact with the formation must not contain any. Solids larger than 2 micron size. Complete Fluid Loss Control

To be effective, particles must not be allowed to move past the face of the formation into the pore system.

OIL FLUIOS-Practical APPLICATION •Availability makes crude oil a logical choice where its density is sufficient. •Density considerations may make it particularly desirable in low pressure formations • Low-viscosity crude has limited carrying capacity and no gel strength and thus should drop out non-hydrocarbon solids in surface pits.

• Oil is an excellent packer fluid from the standpoint of minimizing corrosion, and gel strength can be provided to limit solids settling.

•Loss of oil to the formation is usually not harmful from the standpoint of clay disturbance or from saturation effects Crude oil should always be checked for the presence of asphaltenes or paraffin’s that could plug the formation. This can be done in the field using API Fluid loss test equipment to observe the quantity of solids collected on the filter paper. •Crude oil should be checked for possibility of emulsions with formation water. •Diesel Oil-This may be ideal where an especially clean fluid is required for operations such as sand consolidation It may even be advantageous to work under pressure at the surface where the density of diesel oil is not sufficient to overcome formation pressure

CLEAR WATER FLUIDS-Practical APPLICATION Source of Water •Formation Salt WaterWhen available, formation salt water is a common workover fluid since the cost is low. If it is clean, formation salt water is ideal from the standpoint of minimizing formation damage due to swelling or dispersion of clays in sandstone formations. •Seawater or Bay WaterDue to availability, it is often used in coastal areas. Again, it frequently contains clays and other fines that cause plugging. Untreated bay- water caused serious plugging of Cypress sandstone cores. Depending on the salinity of Bay water, it may be necessary to add NaCl or, KCL to prevent day disturbance

•Prepared Salt WaterFresh water is often desirable a basic fluid due to the difficulty of obtaining clean sea or formation water Desired type and amount of salt is then added. Where clean brine is available at low cost, it may be preferable to purchase brine rather than mix it on location.

Practicalities •From the standpoint of preventing formation damage in sandstones due to disturbance of montmorillonite or mixed-layer clays, the prepared salt water should, theoretically, match the formation water in cation type and concentration.

•It is difficult to match formation brine, however, and laboratory results show that 1% to 5% sodium chloride, 1 % calcium chloride, or 1 % potassium chloride will limit swelling of clays in most formations. •Limitations of CaCl2-In certain formations sodium montmorillonite can be flocculated (shrunk) by contact with calcium ions even in low concentrations. Thus, the clay may become mobile and could cause permeability reduction.

•Where this is the case, 1% or 2% potassium chloride should be used rather than calcium chloride since the potassium ion will prevent swelling in addition, low concentrations will not flocculate the sodium montmorillonite.

PERFORATION FLUIDS Perforating fluids are not necessarily-a distinct type of fluid, but are distinguished here to emphasize the importance of perforating in a nosolids fluid . •Salt Water or Oil When clean, these do not cause, mud plugging of perforations, but if the pressure differential is into the formation, fine particles of charge debris will be carried into the perforation. •Acetic Acid

This is an excellent perforating fluid under most conditions. In the absence of H2S, acetic acid can be inhibited against any type of steel corrosion for long periods at high temperatures. 

•Nitrogen This has advantages as a perforating fluid in low pressure formations, or where rig time or swabbing costs are very high, or where special test programs make it imperative that formation contamination be avoided. •Gas Wells These can be completed economically in “clean fluid” by perforating one or two holes, bringing the well in and cleaning to remove as much well bore fluid as possible, then perforating the remaining zones as desired.

PACKER FLUIDS Criteria Water-base drilling mud as used today are generally not good packer mud.

An acceptable packer fluid must meet two major criteria:

•Limit settling of mud solids and/or development of high gelation characteristics. •Provide protection from corrosion or embrittlement.

PACKER FLUID RECOMMENDATIONS Condition A •No high strength pipe involved in completion (N-80 is borderline case). •Packer fluid density of less than 11.5 ppg required.

Recommendation: 1. Use diesel oil or sweet crude treated with an inhibitor where density requirements permit. 2. Use clear water or brine with an inhibitor and a biocide. Inhibitor and biocide must be compatible.

Condition B •No high strength pipe involved in completion. Fluid density greater than 11.5 ppg required. Bottom-hole temperature does not exceed 300°F. Recommendation:

1. Economics of work over must be considered. Where walkover are inexpensive, a water-base mud treated with a biocide might be economical. Tests should be made to ascertain that mud does not contain soluble Sulfide: pH should be maintained at 11.5 for a few days prior to  completion if possible. Solids should be kept to a minimum to avoid gelation with high pH. 2. In remote locations where workovers are expensive or where workover frequency has been found to be high with water-base muds, use a properly formulated oil mud.

Condition C A.No high strength pipe involved in completion. Density of more than 11.5 ppg required. Bottom-hole temperature exceeds 300°F. Recommendation: 1. Use properly formulated oil mud. Condition D •High strength pipe to be used. Under any condition of fluid density or bottom-hole temperature.

Recommendation: 1. Where fluid density requirements permit, use oil treated with both an oil-soluble and a brine-dispersible corrosion inhibitor. 2. Use oil mud formulated to meet density and temperature requirements.

Well KIWNG 'Circulation rather than bull heading is the preferable, way to kill conventional completions. An adjustable choke should be used to hold casing back pressure on the formation when killing a well by circulation. For a high pressure well, a Swaco well. Control choke may be desirable.

For single completions on a packer, the recommended procedure is as follows: •Fill the annulus. •Open circulating, port in tubing or punch hole in tubing above packer. •Pump slowly down casing-tubing annulus (1/4-1/2 BPM) as wireline tools are retrieved to build up a back pressure on formation. •After wire line tools are retrieved, pump at a constant rate of 2-3 BPM to build up 200--300 psi on tubing. •Maintain a constant pump rate and manipulate the adjustable choke, controlling tubing returns to keep casing pressure constant.

For a tubing less completion or where circulation is not possible bull heading a non-damaging fluid is best if formation will take fluid without breakdown or fracture. Here are four important points. •Breaking down the formation may cause difficult squeeze cementing and producing problems. •For "bullhead" well killing the surface pressure plus fluid gradient time’s depth should be less than formation breakdown pressures. •It may be necessary to have a surface pressure regulator to prevent over-pressuring. •It is necessary to break down the-formation; the size of the resulting fracture can be minimized by low injection rates and high fluid loss.

STIMULATION

Stimulation Methods Well stimulation was mentioned as a means of increasing well productivity. Several methods may be applied, depending on the individual situation. The three principal stimulation methods in their chronological order of development are:

1. Nitro-shooting. 2. Acidizing . 3. Hydraulic Fracturing.

•Nitro-shooting The use of explosives to improve productivity is practically as old as the oil industry

•This involves the placing and detonating of an explosive adjacent to the producing strata, the explosion shatters and fractures the rock, which enlarges the borehole and increases permeability, thereby increasing productive capacity. •The explosive is placed in suitable containers (of tell called torpedoes) and lowered to the desired open hole interval. The upper casing is protected by placing a temporary plug, tamped with cement, plastic, and/or gravel above the shot. The shot is detonated with a time bomb. The well must then be cleaned of debris prior to being placed on production. Solidified or gelatin type nitroglycerm is commonly used.

Benefits: 1. 2. 3. 4.

Bore-hole enlargement combined with fracturing. Not selective to single fracture at weakest bedding plane. No hydrostatic or fluid effect on permeability. Stimulant itself relatively inexpensive.

Limitations: 1. Clean out problems and expense. 2. Hazard to personnel, well, equipment. 3. Limited to open-hole completions.

•Acidizing:

Goal of Acidizing

0 _______________ 1 m

Remove Damage and Restore Orginal Well Productivity

•Acidizing involves the injection of acid into an acid-soluble pay zone where Its Dissolving action enlarges existing voids and thereby increases the permeability of the zone. The acid commonly used is 15% hydrochloric (by weight) which reacts with limestone or other carbonates according to the following reaction 2HCI + CaC03 ~ CaCl2 + H20 + CO2 Only the carbonate rocks are generally susceptible to acid treatment; however, some sands have sufficient calcareous content (usually cementing material) to warrant acidization.

Numerous additives are used in the acid, including

 Inhibitors to retard corrosion of casing and tubing.  Non-emulsifying agents are often added to prevent formation of an oil-acid emulsion during the stimulation treatment. Such emulsions, if formed, are often highly viscous and cause permeability damage which can largely cancel the benefits of the treatment. This emulsifying tendency varies with the crude oil, and selection of the proper non-emulsifying agent is best determined from tests with the field crude oil  Since HCl does not react with silicates, it will not dissolve mud cake. Special solutions called mud acids have been developed for this purpose. And are often used, in relatively small volumes, either to prepare the well bore for a conventional treatment, or to serve as the sole means of stimulation.

The chemical nature of mud acid varies among service companies; however, a common type is a mixture of

HCL + HF (hydrofluoric acid),  The hole is initially filled with oil or another fluid, and then acid is pumped down the tubing while the casing annulus valve at the well head is left open to permit discharge of the displaced oil at the surface. When sufficient acid volume has been injected to displace the entire tubing string and annular section opposite the pay zone, the annulus valve is closed. Continued pumping forces the acid into the Formation. Oil is then used to displace the last of the acid. Afterwards, the pressure is released and the well either is allowed to back flow or is swabbed to remove the spent acid and residue, and is then placed on production. In wells completed with tubingcasing packers, slightly altered, but basically similar, methods are used.

In general, the most permeable spots receive the bulk of the treatment. To prevent this, the injection pressure is generally maintained at the highest possible level in an attempt to obtain more uniform treatment.

Of the entire pay selection since this practice is not entirely satisfactory, many methods of selective treating have been developed whereby more uniform coverage is obtained. These include the use of temporary blocking agents, as well as t the use of multiple packer arguments to isolate specified intervals.

There is always some question as to the quantity of acid to be used in a particular case. Generally, a conventional acid job does not create fractures but merely Enlarges existing voids in nearly all cases,

In highly permeable sections where acidization is required only because of damage, a small 500 gallon mud acid treatment may be more than adequate.  In other cases several thousand gallons of Hcl may be required to obtain a reasonable increase in productivity. In unfractured limestone sections, acidization may yield little if any improvement.

Benefits: 1. Moderate bore-hole enlargement. 2. Primarily adapted to formations of appreciable calcareous content (not generally adaptable to sandstone). 3. Cleans out, enlarges, and interconnects fractures, vugs, other channels. 4. Stimulant relatively inexpensive. 5. Adaptable to both open-hole and set-through completions.

Limitations: 1. May require residue cleanout. 2. Somewhat hazardous and corrosive.

•Hydraulic Fracturing The basic procedure involves the injection of a fracturing fluid and propping agent into the pay zone under sufficient pressure to open existing Fractures and/or create new ones.

These are extended some distance around the well by continued High pressure injection after the initial breakdown or rock rupture has occurred. Upon cessation of pumping (as pressure is reduced) the fractures remain open, being held in place by the propping agent, a carefully sized, silica sand. This process is applicable to virtually all reservoir rocks and may be combined with acid treatments in limestone areas.

The idea of using a propping agent to prevent fracture closing was the key to the new method's success. The sand most commonly used as a propping agent is 20-40 mesh, (.0328 - .0164 in) well rounded, silica sand. Which has a packed permeability of about 300 darcys.

•Fracture fluid: Early fracture techniques generally utilized thickened gels made from kerosene and diesel oil. Currently, lease crude oil is the principal Fracture fluid; it may be thickened by additives if necessary for sand suspension. Fluids native to the formation are less prone to damage permeability and should be used if available.

Gas wells have been treated with water-base fracture fluids, however, fresh water should not be used if the sand is susceptible to clay swelling. Combined acid-fracture treatments using gelled acid or acid-oil emulsions have been successfully applied in various carbonate areas.

•Sand-fluid ratio: Sand concentrations of 1/2 to1/4 lb/gal have been frequently used in fracturing. It is difficult to define any universally applicable optimum concentration and quite possibly such a figure may vary with the area. From field experience, it appears that 1 to 2 lb /gal is the most commonly applied range of concentration.

•Injection rate during treatment Injection rates are controlled by the 1. fracture fluid flow properties, 2. available pump horsepower, and 3. the size of the injection string (tubing or casing).

•Size of treatment In moderate to high permeability zones which have been badly damaged during completion, small treatments may be completely adequate.  In tight zones, the large volume treatment may give optimum results. The economics of treatment size requires careful analysis; it is certain that considerable

Benefits: 1. No bore-hole enlargement. 2. Highly flexible procedure: a. Permits multiple or single fracture. b. Can combine advantages of fracturing and acidizing. c. Wide latitude of sand-carrier agent. 3. 4. 5. 6.

Maximum effective area of stimulation. Maximum extension of inherent or induced fractures. Propping agent maintains high permeability. Permits relatively localized fracture level if desired (in approximately horizontal bedding planes). 7. Adapted to either open-hole or set-through completions.

Limitations: 1. 2. 3. 4. 5.

May involve c1eanout of propping sand. Somewhat hazardous with some carriers. Relatively expensive. High pressures may damage tubing or casing. Intricate down-hole operations requiring packer manipulations.

 SQUEEZE CEMNTING

Squeeze Cementing The technical literature contains a number of papers on squeezing wells. Still, many unanswered questions are frequently asked. • Where does the cement go on a squeeze job? • What is formation breakdown and is it necessary? • Should water or mud be used for breakdown? • Will squeezed cement completely surround a wellbore? • Can perforations be plugged with cement? • Can the quantity of cement be controlled during placement?

Squeezing is widely used in wells for the following purposes • supplementing a primary cementing job that may be deficient because of channeling or insufficient fillip. • Reduction or elimination of water intrusion from above or below the hydrocarbon producing zone.

• Reduction of the gas-oil ratio by isolating the oil zone from an adjacent gas zone. • Repair of a casing leak that might have developed due to corrosion, pressure parting or joint leaks . • Abandoning of old perforations or plugging of a depleted or watered-out producing zone.

Cement Does Not Enter Formation Matrix • The cement filtrate is pumped into the permeability while the cement particles form a filter cake of cement. • As the filter cake builds, the pump-in pressure increases until a squeeze pressure less than fracturing pressure is attained. • It is obvious that the permeability must be high enough to accommodate a reasonable pump-in rate before this ideal squeeze procedure is attained. • Fracturing is usually not the objective of squeeze cementing but rather pump-in pressure is commonly required to determine if a zone will take fluid or cement. • Pump-in pressure is that pressure which is required to push only the cement filtrate into the formation .

Mud-Plugged Perforations • Perforations will usually have some degree of mud fill-up, depending on the completion fluid or primary cementing technique and the breakdown process. • Mud filter cake is capable of withstanding high pressure differentials, especially in the direction from the wellbore to the formation and the high pressures may create a fracture before accepting cement filtrate. • Selective breakdown and cleanup of single perforations prior to a stimulation treatment have revealed the presence of as much as 1000 psi higher pressure on an adjacent perforation. • Many squeeze failures may be attributed to subsequent cleanup of a previously plugged perforation which did not accept the cement slurry during the squeeze job.

Fractures are Created • Even though it is desirable to squeeze without breaking down the formation, in almost all instances, a fracturing pressure must be attained to get the formation to take fluid . • This undesirable condition may be caused by the perforations being blocked or by low formation permeability .

Cement Compressive Strength and Squeeze Pressure • The compressive strength required for a successful squeeze Job may be overemphasized. • The typical perforation cavity has a shape that tends to make the set cement plug act as a check valve in both directions. • A cement filled induced fracture has more bonding area; therefore, it is capable of withstanding more differential pressure than a perforation cavity. • The final squeeze pressure required for a successful job is just enough to dehydrate the cement so that it will not flow back . • A good guide for a squeeze pressure is 500-1000 psi above the pump-in pressure with no flow back in 3-5 minutes.

Design For Pressure • Design the wellhead equipment and tubular goods to accommodate the maximum anticipated squeeze pressure. . This fundamental is rarely overlooked. However, the slurry volume as it relates to pressure is a common oversight. • Design the job so that the hydrostatic head of cement slurry at any time during the job will not exceed the wellhead equipment or maximum casing pressure limitations. • The extra time required to circulate the "long way" may exceed the pumping time of the slurry . • A good rule may be that the volume of cement used should not exceed the volume of the tubular goods.

Hole Conditions • It is absolutely necessary for the hole to be in good condition before starting a remedial squeeze job; otherwise, the problems may become multiplied because of some condition that would be adverse to the operation . • The casing should be in gauge, clear of debris, and clear of any residual cement sheath from a previous operation. • A packer miss run may result because the packer seat could not be reached or attained. • A scraper and bit should be run to check this condition and total depth tagged up to be sure fill up is not excessive. • The hole should be circulated until clean and balanced. • . Gas "bullheaded" into the formation ahead of the cement could percolate through the cement and leave the cement honeycombed.

Well Completion Fluid • Well completion fluid should be a clean, non-wall building fluid such as salt or potassium chloride water. • This type fluid may be bullheaded into the formation ahead of the squeeze slurry provided the injection rate and depth are such that the pumping time of the slurry will not be adversely affected. • In the event that mud is required to maintain control of the well, the cement slurry should be spotted as closely as practical to the packer so that the least mud possible is forced into the formation .

Testing Squeeze Equipment • The tubing, tubing-casing annulus, and wellhead equipment should be pressure tested with a tubing tester prior to starting the job. • To make the test, pump a test plug or set the packer in blank pipe. • The test pressure should be equal to or in excess of the anticipated squeeze pressure or the maximum differential pressure as a result of excess cement left in the system.

Packer Seat • A squeeze packer should be set as closely as practical to the squeeze target . • This leaves the least completion fluid in the rathole to be forced ahead of the cement into the formation. • Any appropriate connection that will seat the packer between 30 to 60 feet above the squeeze target will allow an error of one joint of tubing. • Special cases such as a low pressure zone which will require a hesitation-type squeeze may require setting the packer much higher so that the hesitation process may begin with cement below the packer.

Washes and Flushes • Since perforations may be partially filled with mud, especially if mud is the completion fluid, consideration should be given to that condition prior to a squeeze job . • This condition, if not corrected, may result in one or more of several problems. • The formation may be hydraulically fractured in an attempt to pump into the formation. Since the mud particles cannot enter the matrix of the formation, a mud filter cake will build up. • The mud may contaminate the cement in the perforation cavity or induced fracture, causing a failure. • Do not run a tail pipe below the packer for the purpose of spotting. This could cause the packer to be cemented in the hole.

HIGH PRESSURE SQUEEZING • In high pressure squeezing, a retrievable or non retrievable tool is run on tubing to a position near the top of the zone to be squeezed to confine pressures to a specific point in the hole . • A quantity of salt water (or chemical wash) is used to determine the breakdown pressure of the formation to be squeezed. • Mud should not be used as a breakdown fluid since it can plug or damage the formation. • After breakdown, slurry of cement and water is spotted near the formation and pumped at a low rate. • As pumping continues, injection pressures begin to build up until surface pressure indicates that either cement dehydration or a squeeze has occurred.

LOW PRESSURE SQUEEZING • The low pressure technique has become the more efficient method of squeezing with the development of controlledfluid-loss cements and retrievable packers. • With this technique, formation breakdown is avoided and pressure is achieved by shutting down or hesitating during the squeeze process. • In this hesitation method, the cement is placed in a single stage, but in alternate pumping and waiting period s. • The controlled fluid loss properties of the slurry cause filter cake to collect against the formation or inside the perforations while the parent slurry remains in a fluid state inside the casing.

Low Pressure Fractured Zones • Low pressure fractured zones are often times very hard to squeeze. • These wells normally have a low fluid level and start taking fluid as soon as an attempt is made to load the hole; usually more than one stage of cement is required. • It is extremely important to squeeze with the least possible standing pressure. With a packer used for best control, load the backside and maintain about 1000 psi. • Return in 4-6 hours for another stage. Most likely, a squeeze pressure must be attained by using a hesitation type squeeze-an alternate hesitation and pumping in which the hesitation is to encourage cake buildup. • The first hesitation probably will not decrease the bleed off rate. At this point in the squeeze, it becomes an art rather than science.