Completion Design

COMPLETION DESIGN

INTRODUCTION

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.

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:

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 militarys 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

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

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)

Gun Types and Perforation Methods

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.

There are three basic perforating gun types: Retrievable hollow carrier gun Non-Retrievable or Expendable gun Semi-Expendable gun.

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. Wireline Conveyed Casing Guns

2. Through-tubing Hollow Carrier Guns

3. Through-tubing Strip Guns

4. 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

the well.

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

Shot density in homogeneous, 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.

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

must be kept in mind.

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 1-

inch), 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

Completion fluid in wellbore

Oil or gas

reservoir

Casing

Cement

Pres< phyd > pres

Perforating gun

Perforations can

be plugged with

debris in wellbore

Pressure

controls well

during

completion

Underbalanced Perforating

Completion fluid in wellbore

Oil or gas

reservoir

Casing

Cement

Pres> phyd < pres

Perforating gun

Perforations will

be clean from

surge in wellbore

Well will be

live and need

control after

perforating

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

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;

1- Open Hole Completions

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:

Slot widths depend on the size

of the sand grains in the

formation and are typically

from 0.01 ins. wide upwards,

Slotted Liner

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 hang-

off system

Seal movement device to accommodate tubing elongation or

contraction

Availability of down hole circulating device

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.

Requirements for down hole corrosion inhibitor injection

Requirements for down hole hydrate inhibitors

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.

Wireline Nipples

Permits the installation of flow controls or plugs.

Tubing Retrievable Safety Valve

For emergency well shut-in.

Safety Valve Landing Nipple

Permits the installation of a Surface Controlled 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.

Other equipment commonly installed in tubing string

completions to facilitate safer production may be:

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.

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.

There are various artificial lift completion methods and the

key completion considerations are:

Hydraulic pump lift is utilized in crooked holes, for heavy oils

and variable production conditions that cause problems for

conventional rod pumping.

Hydraulic Pump Lift

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

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.

Single Zone Completions

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:

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.

A. Bell Guide

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.

B. Mule Shoe

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 :

Applications

1- Single and dual completions

Benefits

1- Maximum reliability and

simplicity of locating

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

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

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.

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.

Side pocket valves, which provide a seal above and below

the communication ports, include:

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.

Circulation Valves

these are used to circulate fluids from the annulus to the

tubing without damaging the pocket.

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.

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.

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).

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 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.

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

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.

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

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

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.

flanges. Typically, from bottom to top, an Xmas Tree will contain

the following valves:

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.

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.

3- Permanent/ Retrievable Packer Systems

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 susceptibility

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 paraffins 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 Water- When 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 Water- Due 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 Water- Fresh 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 no-solids 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.

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.

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.

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 300F.

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 300F.

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 times 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.

Solidified or gelatin type nitroglycerm is commonly used.

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.

Benefits: 1. Bore-hole enlargement combined with fracturing. 2. Not selective to single fracture at weakest bedding plane. 3. No hydrostatic or fluid effect on permeability. 4. Stimulant itself relatively inexpensive.

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

Goal of Acidizing

Remove Damage and Restore Orginal Well Productivity

0 _______________ 1 m

Acidizing:

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 tubing-

casing 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. Maximum effective area of stimulation. 4. Maximum extension of inherent or induced fractures. 5. Propping agent maintains high permeability. 6. Permits relatively localized fracture level if desired (in approximately

horizontal bedding planes). 7. Adapted to either open-hole or set-through completions.

Limitations: 1. May involve c1eanout of propping sand. 2. Somewhat hazardous with some carriers. 3. Relatively expensive. 4. High pressures may damage tubing or casing. 5. 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 controlled-fluid-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.