Work Over & Stimulation - Mid 2 (B.tech,M.tech )

Well Completion, Workovers and Stimulation

Well Completion Design


What is a oil and gas well?

•Well is a source or conduit of communication with underground reservoir or producing formation.

•The effectiveness of communication is a vital factor in reservoir drainage as well as overall economics.

•Well represent a major expenditure in reservoir development.

•The individual well completion must be designed to yield maximum overall profitability on a field basis.


Factors influencing completion design:•Reservoir considerations.•Reservoir pressures of various formations over lying the producing formations.• reservoir Pressures of hydrocarbon bearing formations •Production rate •Number of reservoirs or formations likely to produce hydrocarbons.•Reservoir drive mechanisms •Secondary/tertiary recovery methods envisaged•Stimulations technique likely to be utilized down the timeline.•Well interventions likely to be performed from time to time.•Reservoir heterogeneity or uniformity•Stimulation techniques likely to be utilised down the time line and Nature of techniques.•Well intervention methods envisage to b adopted


Factors influencing completion design: Reservoir Drive Mechanism

In Dissolved Gas Drive Mechanism the source of pressure is principally and primarily the liberation and expansion of gas from the oil as pressure is reduced.

With no attempt to maintain pressure by fluid injection pressure peaks declines rapidly, GOR peaks rapidly, primary oil recovery is relatively low . Recompletion could not be expected to reduce GOR

Dissolved Gas Drive Mechanism

A – Original Condition B- 50% Depleted

Well Completion Design Factors influencing completion design: Reservoir Drive Mechanism

In dissolved –gas –drive wells need to be spaced in regular pattern throughout the reservoir in low structural relief throughout the reservoir provided the formation is not stratified (refer Figure A on the left).

In dissolved-gas-drive it is prudent to avoid drilling in structurally high wells. Fig. B on right side

Dissolved Gas Drive Mechanism

A – Dissolved Gas Drive–low angle of dip B-Dissolved Gas Drive High Angle of Dip


Factors influencing completion design: Reservoir Drive Mechanisms:

A water drive uses primarily expansion or influx of water from outside and or below the reservoir. Pressure remains high, GOR remains stable and relatively high.

Down structure wells soon begin to produce formation water.

Eventually even up-structure wells do produce significant amount of formation water.

The effect of the reservoir drive mechanism on producing well characteristics must be taken into deciding about completion at the initial stage of completion and later while recompleting the well during W/O operations.

Water Drive Mechanism Gas Cap Drive

Gas Cap

Oil Zone

Water Zone


Factors influencing completion design: Reservoir Drive Mechanisms:

A water drive uses primarily expansion or influx of water from outside and or below the reservoir. Pressure remains high, GOR remains stable and relatively high.

Down structure wells soon begin to produce formation water.

Eventually even up-structure wells do produce significant amount of formation water.

The effect of the reservoir drive mechanism on producing well characteristics must be taken into deciding about completion at the initial stage of completion and later while recompleting the well during W/O operations.

Water Drive Mechanism Gas Cap Drive

Gas Cap

Oil Zone

Water Zone

Wellheads & Christmas Trees


Wellhead and X-mas Tree

Wellhead and Christmas Tree -Typical

Wellhead and Christmas Tree – Typical - Components


Wellheads & Christmas Trees - Components

Wellhead & Christmas Tree

Wellhead & Christmas Tree - Components


Wellhead Cut out

Christmas Tree - Components

Wellhead – Integral Type

Wellheads & Christmas Tree – Cross and Tee

Wellheads and Christmas Tree Clamp Type

Wellheads & Christmas Tree

Wellhead & Christmas Tree Clamps

Wellhead & Christmas Trees Introduction

Wellhead Equipment: General term used to describe equipment attached to the top of the tubular goods used in a well-to support the tubular strings, provides seals between strings, and control production from the well.

The American Petroleum Institute (API) is an active organization set up to establish standards in sizes, grades, designs, dimensions, and quality to provide safe interchangeable equipment for the industry,.

This section is confined to equipment for the industry, covered by API Spec. 6A for wellhead equipment.

Well Heads & X-mass TreesThe most visible part of the surface equipment of a production or injection well excluding lift equipment and surface piping is what most call as the wellhead.

The American Petroleum Institute published and maintains API Specification 6A, “Specification for wellheads and Christmas Tree”.

This Specification defines a standard nomenclature for definition of components for the definition of components and describes manufacturing requirements for the components.

Wellhead & Christmas Trees

There are two types of API Well head Equipment• API Flanged• Clamped

Wellheads and Christmas Trees

Pressure containment

When drilling a well on land or onshore, a spool wellhead system is traditionally used, as shown in Figures earlier. This wellhead is considered a “build as you go” wellhead system. It is assembled as the drilling process/operation proceeds. The spool system consists of the following main components:

•Starting casing head. •Intermediate casing spools. •Slip casing hanger and seal. •Tubing spool (if well is to be tested and/or completed). •Studs, nuts, ring gaskets, and associated accessories required to assemble the wellhead.

Wellhead & Christmas TreeStarting casing head

The starting casing head (see opposite Figs. ) is attached to the surface casing (conductor) by either welding or threading on to the conductor.

The top of the starting casing head has a flange to mate with the bottom of the BOP. The flange must meet both size and pressure requirements.

The starting casing head has a profile located in the inside diameter (ID) that will accept a slip-and-seal assembly to land and support the next string of casing.

The slip-and-seal assembly transfers all of the casing weight to the conductor while energizing a weight-set elastomeric seal.

Wellheads and Christmas Trees Intermediate casing spoolsIntermediate casing spool is typically a flanged-by-flanged pressure vessel with outlets for annulus access (see Fig. ).

The intermediate casing spool (or spools) is installed after each additional casing string has been run, cemented, and set.

The bottom section of each intermediate casing spool seals on the outside diameter (OD) of the last casing string that was installed.

The bottom flange will mate with the starting casing head or the previous intermediate casing spool.

The top flange will have a pressure rating higher than the bottom flange to cope with expected higher wellbore pressures as that hole section is drilled deeper. Intermediate casing spool also incorporates a profile located in the ID, which accepts a slip-and-seal assembly similar to the one installed in the starting casing head. This slip- and- seal will be sized in accordance with the casing program.

Wellheads and Christmas Trees Tubing spool

The tubing spool, as shown in Fig. opposite, is the last spool installed before the well is completed.

The tubing spool differs from the intermediate spool in one way:

it has a profile for accepting a solid body-tubing hanger with a lockdown feature located around the top flange.

The lockdown feature ensures that the tubing hanger cannot move because of pressure or temperature.

The flange sizes vary in accordance with pressure requirements.

Wellhead & Christmas Tree Load-carrying components

Casing weight is transferred to the starting casing head and intermediate spools with two different types of hanger systems:

• A slip-and-seal casing-hanger assembly. • A mandrel-style casing hanger.

The slip-and-seal casing-hanger assembly (see Figure opposite) has an OD profile that mates/matches with the internal profile of the starting casing head and intermediate casing spools.

Integral to this casing-hanger assembly is a set of slips with a tapered wedge-type back and serrated teeth that bite into the OD of the casing being suspended.

Photo of a typical weight-set slip-and-seal assembly with casing-head installation components.

Wellhead & Christmas Tree

Tubing Hangers

Traditionally, mandrel hangers, as shown in opposite Fig. are used only to suspend tubing from the tubing head.

Occasionally, they can also be used in intermediate casing spools as an alternative to the slip-and-seal casing-hanger assembly.

The mandrel hanger is a solid body with a through-bore ID similar to that of the tubing or casing run below, and it also has penetrations for down-hole safety valve line(s) and temperature and pressure gauges, if required.

Traditionally, in spool wellheads, elastomeric seals are used to seal the annulus between the casing-spool body and the casing or tubing hanger.

Cutaway of Mandrel Type Tubing Hanger

Wellhead & Christmas Tree Tubing Hangers

Casing Hangers

Wellheads & Christmas Tree Annulus seals

The seals used on spool wellhead systems are traditionally elastomeric. This is primarily because the seal must be energized against the casing-bowl ID, and must also seal against the rough finish of the casing OD.

This elastomeric sealing system is used for the slip-and-seal assembly, as well as the bottom of the intermediate casing or tubing spools. The slip-and-seal assembly (see opposite figure ) provides a primary annulus seal, while the elastomeric seal in the bottom of each casing and tubing spool also provides a seal.

The casing-spool flange connection becomes a secondary seal for both annulus and wellbore pressure.

The elastomeric seals are manufactured using different materials to allow for various pressures, produced fluids, and other environmental conditions.

The exception is the seal between each flange face, which is a metal-to-metal sealing ring gasket that provides a pressure-tight seal between each of the spool flanges. Ring gaskets are also used between the wellhead and the BOP stack, as well as the valves used for annulus access

Wellheads & Christmas Tree Product material specifications

When ordering wellhead equipment, the following should be considered:

All surface wellhead equipment and gate valves should be manufactured to:

•The latest edition of the American Petroleum Inst. (API) and

•International Organization for Standardization (ISO) standards.

•National Association ot corrosion Engineers

These standards define equipment specifications as follows:

1.Material class: based on produced fluids; AA, BB, CC, DD, EE, FF, and HH.

2.Tables available in the API specs cover typical gate-valve sizes and trims. These trims are also applicable to surface wellheads.

3.Temperature range: 75 to +350°F.

4.Review the relevant API specifications for your application or consult your equipment supplier for further information.

Well Completion, Workovers and StimulationTypes of wellhead systems

Wellhead systems differ by well location:

•Land •Surface locations offshore (jackup or platform) •Subsea

Offshore wellhead systems are normally more sophisticated in design to handle ocean currents, bending loads, and other loads induced by the environment during the life of the well.

Some of these loads are cyclic in nature, so fatigue-resistant designs are desirable, particularly for deepwater developments. Material specifications play an important role in equipment performance; helpful standards are available from organizations such as:

•American Petroleum Institute (API) •American Society of Mechanical Engineers (ASME) •National Association of Corrosion Engineers (NACE Intl.)

http://petrowiki.org/Wellhead_systems_for_land_drilling

http://petrowiki.org/Mudline_suspension_system

http://petrowiki.org/Jackups

http://petrowiki.org/Fixed_platform_rigs

http://petrowiki.org/Subsea_wellhead_systems

Wellheads and Christmas Trees – Offshore wells Types of wellhead systems (Continued)

In certain applications such as deepwater platforms, spars, and tension-leg platforms (TLPs), surface wellheads and subsea wellheads are used together to safely produce hydrocarbons.

In water depths of 500’ to 1,400’, subsea wellheads are used to explore and develop offshore fields.

Deepwater production platforms can be placed over these wells and tied back to the subsea wellheads; the top termination of the tieback at the platform will typically use surface unitized wellheads with solid block Christmas trees (which have fewer leak paths) as pressure-controlled access points to each well.

Spars and TLPs are floating vessels used in deep water up to 4,500 ft. The wells are drilled using subsea wellheads, which are then tied back to the production deck of the spar or TLP, again using unitized wellheads and solid block trees to safely control and produce the well. For these special applications, it is strongly recommended to seek the advice of equipment supplier for more detailed information.

http://petrowiki.org/Fixed_platform_rigs

http://petrowiki.org/Unitized_wellhead

Wellheads & Christmas Trees – Pressure Ratings

API Pressure Rating , MPa API Pressure Rating in Psi

13.8 2,000

20.7 3,000

34.5 5,000

69.0 10,000

103.5 15,000

138.0 20,000

Nominal Pressure Rating of Wellheads and Christmas Trees

De-rated Pressure Ratings of Wellheads and Christmas Trees

Pressure Rating, De-rated Pr. Rating De-rated Pr. Rating

Class K to U Class X, MPA(PSI) Class Y, MPa( PSI

13.8(2000) 13.1(1905) 9.9(1430)

20.7(3000) 19.7(2860) 14.8(2,145)

34.5(5000) 32.8(4,765) 24.7(3575)


API Specification 6A (ISO 10423) recommends product specification levels (PSLs) for equipment with quality control requirements for various service conditions.

PSLs apply to primary equipment:

•tubing heads

•tubing hangers, hanger couplings

•tubing head adapters

•lower master valves

All other wellhead parts are classified as secondary. The PSL for secondary equipment may be the same or less than the PSL for primary equipment.

Well Completion – Tubing Very frequently tubulars used in O & G industry is termed as Oil Country Tubular Goods (OCTG)

Once the casing is run and held in place with cement, production tubing is run into the oil and gas well.

These tubings do comply with API Specification 5CT.

Singles of tubing are connected together with couplings to make up a tubing string. Running tubing into an oil & gas well is much the same as for running in casing, but tubing is smaller in diameter and is removable.

The production string provides a continuous bore from the reservoir to the wellhead and together with the other components of the production string, produces oil and gas at the surface.

As opposed to casing, production tubing is designed to enable quick, efficient, and safe installation, removal and re-installation.

Oil and gas is also produced more effectively through tubing than through larger-diameter production casing.

Well Completion – Tubing Sizes

OD of Tubing, Inches Corresponding Poundage, PPF

1.050” 1.14 PPF to 1.54 PPF

1.315” 1.70 PPF to 2.24 PPF

1.660” 2.09 PPF to 3.07 PPF

1.900” 2.40 PPF to 5.15 PPF

2.063” 3.24 PPF to 4.50 PPF

2 -3/8” 4.00 PPF to 7.45 PPF

2-7/8” 6.40 PPF to 11.50 PPF

3-1/2” 7.70 PPF to 17.00 PPF

4” 9.50 PPF to 22.20 PPF

4-1/2” 12.60 PPF to 26.10 PPF

Well Completion – Tubing Sizes

Grades: H40, J55, N80, N80Q, L80, C90, C95, T95, P110, 13CR

Connections: NUE (non-upset tubing),EUE (external upset tubing),IJ (integral joint tubing),

In industry some manufacturers produce semi-premium and premium connections. And a few others with Metal One Connections.

Lengths : Range 1, Range 2 & Range 3

Well Completion – Tubing Sizes & Technical Specifications

Protection:

• External Bare and Uncoated or • Externally Coated with Anti-Rust Mill Varnish Plastic or • Metal Pin and Box Protectors or• Internal Plastic Coating or • Sleeves.

Mill Test Certificates Issued in accordance with API Specification 5CT Eighth Edition.

Third Party Inspection can be performed on request at buyer’s care and expense.

Tubing sizes and Technical Specifications API Physical Properties Specifications

API Grade Yield Strength, psi Yield Strength, psi Min Tensile Strength, Psi*

Min elongation in % in 2”

Minimum Maximum

H-40 40,000 80,000 60,000 29.5

J-55 55,000 80,000 75,000 24.0

L-80 80,000 95,000 95,000 19.5

N-80 80,000 110,000 100,000 18.5

C-90 90,000 105,000 100,000 18.5

C-95 95,000 110,000 105,000 18.0

T-95 95,000 110,000 105,000 18.0

P- 110 110,000 140,000 125,000 15.0

Note: * Based on Where, e = Minimum elongation in 2 inches, %A= Cross sectional area square inU =Tensile strength, psi

High strength tubing is usually considered to be grades with Yield strength > 55,000 psi

Tubing String - DesignTubing string design is essentially same as for Casing.

Tapered string design are becoming more common in deep and super deep wells, although uniform design is desirable (but more expensive) and sometimes technically not possible.

Tensile – Setting Depths in air for Upset Tubing, in Feet:

Grade/ Safety Factors 1.50 1.60 1.75

J-55 10,200 9,600 8,700

C-75 13,900 13,000 11,900

N-80 & L-80 14,800 13,900 12,700

C-90 16,700 15,700 14,200

C-95 & T- 95 17,800 16,500 15,000

P- 110 20,400 19,200 17,380

Note: Based on Minimum yield strength times area of section under root of last perfect thread, or body of pipe whichever is smaller. Tension design factor of 1.60 is common for uniform tubing string

Tubing String - Design

Numerical values of tensile strength must be used with care and in prudent manner

Since it is determined under very restrictive conditions or uni-axial loading and may not relate closely to the complex conditions or stress and environment encountered in real life in fields.

All tubing string get subjected to :•Tension or elongation•Collapse pressure•Burst Pressure

Safety factors for Collapse should NOT be less than 1.00

Tubing should NOT be subjected to burst pressure higher than its rated pressure divided by 1.3

Tubing String - DesignYield and Tensile Strengths

The tensile test provides basic design information on the strength of materials.

This test subjects a standard specimen of that Grade to a gradually increasing load.

At relatively low loads (elastic range) elongation is directly proportional to the load applied and permanent deformation does not occur.

As load increases, a point is reached where elongation occurs with no increase of load – called as Yield Point.

The load at this point divided by specimen cross sectional are is Yield Strength.

Further increase in load causes permanent deformation (plastic range) and finally specimen breaks.

Load at the breaking point determines the tensile strength or ultimate strength.

Tubing and Casing – Identification – Colour Band

H-40 One Black ( or no marking)

J-55 One Green

K-55 Two green

C-75 One Blue

N-80 One Red

L-80 ( Type 1) One Red, One Brown

C-90 One Purple

C-95 One Brown

T-95 One Silver

P-110 or P-105 One White

Q -125 One Orange

Special clearance collars are usually marked with a black ring in the centre in the band indicating steel grade

Tubing Connections There are following two standard API Connections

1. API non-upset (NU) connections

2. API External Upset (EUE)

API non-upset (NU) connections: 10 round thread form cut on the body, wherein the joint has less strength than the body.

API External Upset (EUE): 8 round thread form wherein the joint has the same strength as the pipe body.

For high pressure service the API EUE connection is available in 2-3/8”, 2-7/8” & 3-1/2” sizes having a long thread form (EUE long T&C) wherein the effective thread is 50% longer than standard.

Many operators prefer a teflon ring insert rather than the long thread form.

Tubing Connections Special clearance Couplings:Where extra clearance is needed, API couplings can be “turned down” somewhat without loss of joint tensile strength. Special clearance collars are usually marked with a black ring in the centre in the band indicating steel grade.Special clearance coupling-type thread forms have been developed for NUE tubing which (unlike the API NU) connection) have 100% strength. Buttress connection is an example.Standard and “turned down” diameters of several API coupling connections are given the Table given hereunder

Standard and Special Clearance Tubing Coupling Sizes

Thread Coupling OD , inches Coupling OD, inches

Standard Special Clearance

2-3/8”

API NU – 10 rounds 2.875” 2.642”

API EUE – 8 rounds 3.083” 2.910”

Buttress 2.875” 2.700

2-7/8”

API NU – 10 rounds 3.500” 3.167”

API EUE – 8 rounds 3.688” 3.460”

Buttress 3.5” 3.220”

Standard and Special Clearance Tubing Coupling Sizes

Integral –Joint (IJ) Connections:Several integral joint forms are manufactured by many

companies. These connections provide extra clearance.

Some can be turned down further to provide even greater clearance.

These joints usually carry a premium price and must, therefore be justified by special connections.

API has adopted special clearance diameter tubing even for smaller diameter tubing like 1.315”, 1.660”, 1.900” & 2.061”.

Well Completion - Tubing size

Maximum size of Tubing is determined from erosional velocity factor given by following empirical relation ship

Where Ve –fluid erosional velocity, ft/sec.c- empirical constant. Varies in between 80 to 300. Usually c=125 for intermittent service, or 100 for continuous service.ρm – gas liquid mixture density, lbs/ft3

API Working Pressure & Body Test PressureWorking Pressure, Psi

Flanges – 14” & smaller

Flanges 16-3/4” & more

Clamp Type Connectors

Line Pipe & Tubing Threads

1,000 2,000 1,500 - 2,000

2,000 4,000 3,000 4,000 4,000*

3,000 6,000 4,500 6,000 6,000*

5,000 10,000 10,000 10,000 10,000*

10,000 15,000 15,000 15,000 15,000*

15,000 22,500 - - -

20,000 30,000 - - -

Note: * When threads are used as end or outlet connections of wellhead or flowline components, the Maximum WP of the assembles joint is given in next Table while test pressure is given above.

API Working Pressure & Testing Casing Threads pressure

4½” to 10¾” 11¾” to 13⅜” 16” to 20”

114.3mm – 273.1 mm 298.5mm -339.7mm 406.4 mm to 508.0mm

2,000 2,000 2,000

- - 2,250

4,000 4,000 -

6,000 4,500 -

7,500 - -

Note: * When threads are used as end or outlet connections of wellhead or flowline components, the Maximum WP of the assembles joint is given in next Table while test pressure is given above.

Physical & Chemical Properties of Casing /Tubing steel

Note: 1.Type 1, Type 2, Type 3 & Type 4 is as per nomenclature of API on standardization of valves and W/H equipment t identify materials falling within the ranges of tensile requirements mentioned above.2.Chemical composition of Types 1, 2, 3 & 4 are omitted deliberately in order to give freedom to manufacturers to develop their own steels for the multiplicity of requirements encountered in the critical service.

Type 1 Type 2 Type 3 Type 4

Tensile strength, psi 70,000 90,000 100,000 70,000

Yield Strength, psi 36,000 60,000 75,000 45,000

Elongation in 2”, minimum , % 22 18 17 19

Reduction in area, Min, % 30 35 35 32

Carbon, Max. % * * * 0.35

Manganese, Max, % * * * 0.90

Sulfur, Maximum, % * * * 0.05

Phosphorus, Maximum, % * * * 0.05

Well Completion – Tubing Response Characteristics Does the length of tubing lowered into a well remain constant?

No….Changing the mode of a well (producer , injectors, shut-in or opening) causes change in temperature and pressures inside and outside the tubing.

Depending upon a) how the tubing is suspended from X-mas tree i.e. open ended or with packer, type of packer and how packer is set, temperature and pressure changes will effect in following manner:

1. Length variation in the tubing string will result if the seals are permitted to move inside a permanent polished bore packer (PBR).

2. Tensile or compressive forces would be induced in the tubing and packer system if tubing motion is not permitted (latched connection).

3. A permanent packer might get unseated if motion is permitted ( tubing contraction) and seal assembly is not long enough.

4. Unseating of a solid–head tension (or compression) packer will occur if it is not set with sufficient strain (or weight) to compensate for tubing movement.

5. Equalizing valve will open prematurely on control head packers (tension or compression)

Tubing Elongation/contraction due to temperature Thermal Expansion or contraction causes the major length change in tubing is given by following relationship:

ΔLt = 8.28x10 -5x Lt x ΔT

WhereΔLt = change in tubing length , ft

Lt = tubing length, ft

ΔT = change in average temperature, F⁰

Length change are calculated readily if the average temperature of tubing can be determined for the initial condition and then again for next operation and next etc.

The average string temperature in any given operating mode is one-half the sum of the temperatures at the top and at the bottom of the tubing string.

ΔT is the difference between the average temperatures of any two subsequent operating modes


Well Completion – Open Hole Completion



Packers

Well Completion, Workovers and Stimulation - Packers

What is packer?

The packers forms the basis of the cased-hole completion design.

The packer: a sealing device that isolates and contains produced fluids and pressures within the wellbore to protect the casing and other formations above or below the producing zone.

Well Completion, Workovers and Stimulation - PackersUses of packers

In addition to providing a seal between the tubing and casing, other benefits of a packer are as follows:

•Prevent downhole movement of the tubing string,

•Support some of the weight of the tubing,

•Often improve well flow and production rate

•Protect the annular section of casing from corrosion from produced fluids and high pressures.

•Provide a means of separation of multiple producing zones.

•Limit well control to the tubing at the surface for safety purposes, and

•Hold well-servicing fluid (kill fluids, packer fluids) in the casing annulus


Packer components

Packers have four key features: 1. Slip 2. Cone 3. Packing-element system 4. Body or mandrel.

Slip is a wedge-shaped device with wickers (or teeth) on its face, which penetrate and grip the casing wall when the packer is set.

Cone is beveled to match the back of the slip and forms a ramp/slope that drives the slip outward and into the casing wall when setting force is applied to the packer.

Once the slips have anchored into the casing wall, additional applied setting force energizes the packing-element system and creates a seal between the packer body and the inside diameter of the casing.


Packer classification

Production packers can be classified into two groups: Permanent. Retrievable

Permanent packers

Permanent packers can be removed from the wellbore only by milling. The retrievable packer may or may not be resettable, but removal from the wellbore normally does not require milling.

Retrieval is usually accomplished by some form of tubing manipulation. This may necessitate rotation or require pulling tension on the tubing string.

The permanent packer - fairly simple and generally offers higher performance in both temperature and pressure ratings than does the retrievable packer.

In most instances, it has a smaller outside diameter (OD), offering greater running clearance inside the casing string than do retrievable packers. The smaller OD and the compact design of the permanent packer help the tool negotiate through tight spots and deviations in the wellbore. The permanent packer also offers the largest inside diameter (ID) to make it compatible with larger-diameter tubing strings and monobore completions. Retrievable packersThe retrievable packer can be very basic for low pressure/low temperature (LP/LT) applications or very complex in high pressure/high temperature (HP/HT) applications. Because of this design complexity in high-end tools, a retrievable packer offering performance levels similar to those of a permanent packer will invariably cost more. However, the ease of removing the packer from the wellbore as well as features, such as resettability and being able to reuse the packer often, may outweigh the added cost.


Permanent packers

Generally, it has a smaller outside diameter (OD), offering greater running clearance inside the casing string than do retrievable packers.

The smaller OD and the compact design of the permanent packer enable us negotiate through tight spots and deviations in the wellbore. The permanent packer also offers the largest inside diameter (ID) to make it compatible with larger-diameter tubing strings.


Retrievable packers

The retrievable packer can be very basic for low pressure (LP)/low temperature (LT) applications or very complex in high pressure/high temperature (HP/HT) applications.

Because of this design complexity in high-end tools, a retrievable packer offering performance levels similar to those of a permanent packer will invariably cost more.

However, the ease of removing the packer from the wellbore as well as features, such as re-settability and being able to reuse the packer often, may outweigh the added cost.


Packer selection

Before selecting either of the two packers, it is important to consider the performance and features of each design, as well as the application in which it will be used.

In some cases, the permanent packer is the only option, as may be the case in some HP/HT applications. However, in those instances in which one would suffice, the operator must decide which features offer the best return over the life of the well.

When selecting a packer for a cased-hole completion, the differential pressure and temperature requirements of the application must be considered.


Packer selection

Other factors to be kept into consideration are:•Well depth,•Casing ID, Casing drift diameter•Deployment and setting method desired, and •Tubing landing conditions•Various operational modes (flowing, shut-in, injection, and stimulation) anticipated over the life of the well. These conditions are critical and must be considered carefully for design and operations.

The changes in the operational modes that influence changes in temperature, differential pressure, and axial loads all have a direct impact on the packer.

Understanding the uses and constraints of the different types of packers do help clarify the factors to consider when making a selection.


Retrievable tension packer

The tension packer generally used in medium- to shallow-depth (LP/LT) production or injection applications.

The tension packer has a single set of unidirectional slips that grip only the casing when the tubing is pulled in tension.

Constant tubing tension must be maintained to keep the packer set and the packing element energized.

Tension packers, typically, are set mechanically and are released by means of tubing rotation.

Most models also have an emergency shear-release feature should the primary release method fail.

Well Completion, Workovers and Stimulation - PackersRetrievable tension packer

Retrievable tension packer do not have an equalizing (or bypass) valve to aid in pressure equalization between the tubing and annulus to facilitate the retrieval of the packer.

Practically NO problems are associated with tension packers, because the packer is run at relatively shallow depths, and differential pressures across the packer during retrieval should be low.

In deep wells tension packers without bypass valves should be avoided.


High differential pressures can make packers difficult or impossible to release because of the forces created by the pressure acting on the cross-sectional area of the packer.

Pressure from below the tool boosts the packing element into the slip assembly, which is designed to hold in tension and capture this force.

On the other hand, when annular pressure is higher than tubing pressure at the tool, the element is boosted downward away from the slips, and pack-off force is lost.

Therefore, it is prudent to ensure that sufficient tension is applied to keep the element energized to contain differentials in favor of the annulus.


Consideration should be given to the type of wellhead and Christmas tree that will be employed when using tension packers in extremely shallow operations.

After the packer is set and tubing is pulled in tension, it is difficult or impossible for the tubing to stretch enough to facilitate installation of some types of wellheads.

Retrievable Compression Packer with Fluid bypass

Retrievable compression packer with fluid-bypass valve is recommended for low to medium-pressure & medium-temperature oil-or gas-production applications.

Retrievable compression packer is prevented from setting by means of a mechanical interlock while it is being run in the hole.

Once the packer has been run to the desired depth, the tubing string is rotated to initiate the setting sequence.

During rotation of string, the drag blocks on the packer are used to hold the packer in place and provide the resistance to set it.

Retrievable Compression Packer with bypass

Once the interlock system is released, the tubing string is lowered to close the bypass seal and set the slips.

The continued application of slack-off force energizes the packing-element system and creates a seal.

The packer is released by simply picking up on the tubing string—a desirable feature.

In this type of packer, once the element is sealed off and the pack-off force is mechanically locked in place, the tubing string may be landed in compression, tension, or neutral.


Slips located above and below the packing element (or a single set of bidirectional slips) are designed to hold axial tubing loads from either direction to keep the packer anchored in place.

An internal lock system mechanically traps the pack-off force and keeps the elements energized until the packer is released.

A bypass valve is present to aid in equalization and the release of the packer. It is locked from accidentally opening until the packer-releasing sequence has been initiated.

This type of packer does not rely on constant tubing forces to maintain its packoff, so it is much more versatile in use.


It is used in production or injection applications, as well as in completions for which well stimulation is planned, and it is almost universal in application.

The only constraint is in deep deviated wells, where tubing manipulation or getting packoff force to the tool may present a problem.

Extreme shallow depth setting is achievable in models that allow the elements to be energized with tension.

Care must be taken to ensure that tubing movement during production or injection operations does not exceed the tensile or compression limitations of either the packer or the tubing string.

Compression Packer with Fluid Bypass

Retrievable Compression Packer with bypass & Hold Down buttons/slip

More versatile models of the compression packer with bypass have an additional set of hold-down slips, or an anchor system above the packing-element system

Setting and releasing procedure same.

However, the addition of the hold-down slip helps to keep the packoff force and bypass valve locked in place when pressure below the tool is greater than the pressure in the annulus. This variation can be used in limited treating operations, in gas lift applications, or in production applications in which tubing pressures are greater than annular pressures. However, there are limitations to the ability of the anchor to keep the bypass closed, and any operational modes that will result in loss of set-down weight must be planned carefully.

Compression Packer with Fluid Bypass & Hold Down Buttons

Compression Packer with Fluid Bypass

Retrievable Compression Packer with bypass & Hold Down buttons/slip

However, the hold-down slip helps to keep the packoff force and bypass valve locked in place when pressure below the tool is greater than the pressure in the annulus.

This variation is used for treating operations, in gas lift applications, or in production where FTWHP > CWHP.

However, there are limitations to the ability of the anchor to keep the bypass closed, and any operational modes that will result in loss of set-down weight must be planned carefully.

Compression Packer with Fluid Bypass & Hold Down Buttons

Wireline Set –Tubing retrieval Packers

Several retrievable packers are designed to be installed in the wellbore on electric wireline and retrieved on the tubing string.

On the top of the packer is located a special nipple.

The nipple has a polished seal surface on its OD and has j-lugs that are used to anchor a seal housing or washover shoe in place.

The polished nipple also has a landing nipple profile in its ID. This allows the installation of a slickline retrievable blanking plug if desired. Set with plug in place (LHS)

With tubing connected & plug retrieved (RHS)


The packer is first run and set on electric wireline.

The electric wireline setting tool provides the force necessary to anchor the slips in the casing wall and energize the packing element.

Once the packer set & installed and the wireline is retrieved.

A seal housing (similar to an overshot) is run in the hole on the bottom of the production tubing.

Set with plug in place (LHS)With tubing connected & plug retrieved (RHS)


The housing has internal seals that, when landed on the polished nipple, create a seal between the tubing and the annulus.

The housing also has an internal j-profile that engages the lugs of the nipple and anchors the tubing string to the packer.

Tubing can be retrieved from the wellbore at any time without disturbing the packer by unjaying the seal housing from the polished nipple, or (if desired) the packer can be released and retrieved mechanically with the tubing. Set with plug in place (LHS)


Wireline Set –Tubing retrieval PackersAdvantages and application• May be run and set under pressure on

electric wireline (with a blanking plug preinstalled in the nipple profile) in a live oil or gas well.

• Once packer is set, the electric line is

Pulled out & pressure above the packer can be bled off.

• With the plug in place, the packer will act as a temporary bridge plug for well control while the tubing string and seal housing are run and landed.

Set with plug in place (LHS)With tubing connected & plug retrieved (RHS)

Wireline Set –Tubing retrieval PackersAdvantages and application• Because the plug is located near the top

of the packer assembly, it can be circulated free of any debris before landing the tubing.

• Once the tree has been installed, the plug is removed with slickline, and the well is placed on production.

Application• Completion of the well after a high-rate

fracture is performed down the casing or after underbalanced perforating with a casing gun.

• This underbalanced completion method is especially useful in applications in which formation damage may occur if kill-weight fluid is introduced into the wellbore. Set with plug in place (LHS)


Retrievable tension/compression set—versatile landing

Tension or compression set packers allows the tubing to be landed in tension, compression, or neutral.

Most common types of mechanical-set retrievable packers available in industry.

They vary greatly in design and performance and may require tension, compression, or a combination of both to set and pack off the element.

Exact setting method depends on the design of the tool.

Available in various packing-element systems & pressure differential ratings.

Retrievable Tension Compression set packer


Extensively used for large number of applications including some HP/HT completions.


In this type of packers, once the element is sealed off and the packoff force is mechanically locked in place - tubing string may be landed in compression, tension, or neutral.

Slips located above & below the packing element (or a single set of bidirectional slips) are meant to hold axial tubing loads from either direction to keep the packer anchored in place.

Internal lock system mechanically traps the packoff force and keeps the elements energized until the packer is released.



Bypass valve is to aid in equalization and the release of the packer.

It is locked from accidentally opening until the packer-releasing sequence has been initiated. Packer does not rely on constant tubing forces to maintain its packoff, this tool is more versatile in application.

It is used in production or injection applications & in completions for which well stimulation is planned.

Almost universal in application.

Constraint - in deep deviated wells, where tubing manipulation or getting packoff force on packer may present a problem.



Extreme shallow depth setting is achievable in models that allow the elements to be energized with tension.

Care must be taken to ensure that tubing movement during production or injection operations does not exceed the tensile or compression limitations of either the packer or the tubing string.

Retrievable Hydraulic – set single string Packer

Retrievable hydraulic-set single-string packerThe hydraulic-set packer has a bidirectional slip system, which is actuated by a predetermined hydraulic pressure applied to the tubing string.

To achieve a pressure differential at the packer and set it, a temporary plugging device must be run in the tailpipe below the packer.

The applied hydraulic pressure acts against a piston chamber in the packer. The force created by this action sets the slips and packs the element off.

Some models have an atmospheric setting chamber and use the hydrostatic pressure of the well to boost the packoff force.

Retrievable Hydraulic –set single string Packer

Retrievable hydraulic-set single-string packer

Regardless of design, all of the force generated during the setting process is mechanically locked in place until the packer is later released.

Once the packer is set, the tubing may be landed in tension (limited by the shear-release value of the packer), compression, or neutral.

As NO tubing manipulation is needed to set a hydraulic packer, it is normally set easily after the wellhead has been flanged up and the tubing has been displaced.

This ensures safety and allows better control of the well while displacing tubing and annulus fluids.



The hydraulic-set packer can be run in a single-packer installation, and because no packer body movement occurs during the setting process, it can be run in tandem as an isolation packer in single-string multiple-zone production wells.

Hydraulic-set single-string packer is ideal for highly deviated wells in which conditions are not suitable for mechanical-set packers.



Special considerations for Hydraulic set packers are:

•Well stimulation planning to be done carefully to avoid premature shear release of the packer.

•Maximum tensile capabilities of the tubing string when selecting the shear-release value of the packer needed.

•A temporary plugging device must always be incorporated below the lowermost hydraulic-set packer to facilitate hydraulic setting of the packer.



Retrieval of hydraulic packer

Retrieval of the hydraulic-set single-string packer is done simply by pull – up tension with the tubing string to shear a shear ring, or shear pins, located within the packer.

Most models also have a built-in bypass system that allows the pressures in the tubing and annulus to equalize, or balance, as the packer is released.

The tension load required to release the packer must be considered carefully at the time of initial completion design and in the selection of the shear-ring value.




The shear-release value must not be set too high so that it will not be beyond the tensile capabilities of the tubing string, yet it must be high enough so that the packer will not release prematurely during any of the planned operational modes over the life of the completion.

A variation of the hydraulic-set single-string retrievable packer is without the shear-release feature, is available for the larger-size casing and tubing combinations.

Retrievable Hydraulic – set single string Packer



This type of Hydraulic packers are called as “removable” packer because it is not retrieved by conventional means.

The running-in & hydraulic setting procedure remain the same, but to remove the packer from the wellbore, the inner mandrel of the packer must be cut.

This is done either with a chemical cutter on electric wireline or by a mechanical cutter on drillpipe or coiled tubing.

Once the mandrel is cut, retrieval is accomplished by picking up on the tubing string or the top of the packer.




The packer is also designed to be millable should the cut-to-release feature fail.

The elimination of the shear ring enables the packer to achieve higher tensile and differential-pressure ratings.

This permits well-treating jobs (hydraulic fracturing etc.) and well-injection operations especially hydraulic fracturing etc. that were not possible with the conventional shear-release hydraulic-set packer.

Dual String Packers

Dual-string packers

A “mid-string” isolation packer that is designed to seal off approximately two strings of tubing.

The dual packer allows the simultaneous production of two zones while keeping them isolated.

Most multiple-string packers are retrievable; however, some permanent models exist for use in HP/HT applications.

Generally these packer have bidirectional slips to prevent movement and maintain packoff with the tubing landed in the neutral condition.

Generally multiple-string retrievable packers are set hydraulically because the tubing manipulation required to set a mechanical packer is not desirable or (often) not feasible in a dual-string application.

Dual String Packers

Dual-string packers

Identical to hydraulic-set single-string packer.

Setting pressure is applied to the upper tubing (short string), but some models are designed to be set with pressure applied to the lower tubing (long string).

A temporary plugging device is required to be run below the dual packer on the appropriate string to allow the actuating pressure to be applied.

Released by applying tubing tension to shear an internal shear ring same way as in shear-value selection that apply to the single-string hydraulic-set packer (as in single string hydraulic packers).

Too high value of shear value can overstress the tubing during retrieval, and too low a value can lead to a premature packer release during one of the various operational modes to which the packer will be exposed.

Dual String Packers

Dual-string packers

Identical to hydraulic-set single-string packer.

Setting pressure is applied to the upper tubing (short string), but some models are designed to be set with pressure applied to the lower tubing (long string).

A temporary plugging device is required to be run below the dual packer on the appropriate string to allow the actuating pressure to be applied.

Released by applying tubing tension to shear an internal shear ring same way as in shear-value selection that apply to the single-string hydraulic-set packer (as in single string hydraulic packers).

Too high value of shear value can overstress the tubing during retrieval, and too low a value can lead to a premature packer release during one of the various operational modes to which the packer will be exposed.

Dual String Packers

Dual-string packers

Over and above well completions of wells with multiple producing horizons these packers include ESP applications in which both the electrical cable and the production tubing must pass through the packer.

Multiple-string packers are also used in tandem to isolate damaged casing. .

Seal-bore Packers

Permanent Seal Bore packers

Seal – bore packers are of two types: 1) Permanent and 2) Retrievable

Permanent (LHS) & retrievable (RHS) sealbore packers are designed to be set on electric W/L or hydraulically on the tubing string.

W/L setting affords speed and accuracy.

However the one-trip hydraulic-set versions offer the advantage of single-trip installations and allow the packer to be set with the wellhead flanged up.

Seal-bore Packers


Seal – bore packers are of two types: 1) Permanent and 2) Retrievable Sealbore packers have a honed and polished internal sealbore.

A tubing seal assembly with elastomeric packing forms the seal between the production tubing and the packer bore.

Well isolation is accomplished by the fit of the elastomeric seals in the polished packer bore.

Seal-bore Packers


Seal – bore packers are of two types: 1) Permanent and 2) Retrievable To accommodate longer seal lengths, a sealbore extension may be added to the packer.

If one-trip hydraulic-set sealbore packer is being used, then production tubing, tubing seal assembly, and packer are made up together and run as a unit.

Seal-bore Packers


Seal – bore packers are of two types: 1) Permanent and 2) Retrievable If the packer is RIH on electric wireline or set on a work string, the seal assembly is run on the production tubing after the packer is installed and stabbed into the packer bore downhole.

Seal-bore Packers – Seal Assembly

Locator Type Anchor Type

Locator type Seal Assembly Anchor Type Seal Assembly

Seal-bore Packers – Seal AssemblyLocator Type

Locator type Seal Assembly

Locator type seal assembly shown in this figure.

It allows seal movement during production and treating operations like stimulation, Fracking etc.

Seal-bore Packers – Seal AssemblyAnchor Type

Anchor type Seal Assembly

Anchor type seal assembly shown in this figure.

It also allows movement of seal during production and treating operations like stimulation, Fracking etc.

Both these types of seal assemblies allows the seals in the packer bore and restricts tubing movement.

Decision about the best seal assembly to run depends on tubing movement and hydraulic calculations based on:

•Initial landing condition of tubing string•Flowing and shut in pressures•Any stimulation job envisaged during the production life span.

All types of stimulation treatments can be carried out on the well.

The removable seal assembly allows tubing to be retrieved for workover without the need of pulling and replacing the packer.

Seal-bore Packers – Seal AssemblyLocator Type and Anchor Type

Anchor type Seal Assembly

Anchor type seal assembly shown in this figure.

Both these types of seal assemblies allows the seals in the packer bore and restricts tubing movement.

Decision about the best seal assembly to run depends on tubing movement and hydraulic calculations based on:

•Initial landing condition of tubing string•Flowing and shut in pressures•Any stimulation job envisaged during the production life span.

All types of stimulation treatments can be carried out on the well.

The removable seal assembly allows tubing to be retrieved for workover without the need of pulling and replacing the packer.





Packer Rating Envelope


Well Completion – Skin effectThe flow of oil and gas into well bore is considered to be of radial cylindrical steady-state type and that fluid velocity is not too great in the vicinity of the wellbore, the flow equation can be simplified to:

Where

PI – Productivity Index, mainly depends on viscosity of the fluid, permeability of the formation itself, the disturbances in the vicinity of the wellbore and the thickness of the reservoir

The Actual Productivity Index (PI) is normally compared with the theoretical Productivity Index (PIth) of a vertical well at the level of producing formation that would have been drilled under ideal condition.

Well Completion – Skin effectIt is implied that having (mostly adversely) interfered with the reservoir characteristics in the near vicinity of wellbore (permeability especially) and with no restrictions on the connection between the reservoir and the wellbore.

The theoretical PIth is as follows:

Whereα – numerical coefficient depending upon, among other parameters on the units that are used.h – reservoir thickness k –reservoir permeabilityµ - viscosity of the fluid in the reservoir,R - Well drainage radiusrw - wellbore radius

Well Completion – Skin effect

As far as real well is concerned, all the disturbances in the vicinity of well bore (skin effect) are lumped together under the term “S” (skin factor) in the following way.

Furthermore, Flow Efficiency (FE) is defined as the ratio between the actual flow rate and the theoretical flow that the “ideal” well would have produced under the same bottom hole pressure conditions.

Well Completion – Skin effectIn practice ln (R/rw)ranges between 7 to 8, hence the simplified form under the prevailing assumptions FE varies as under:

Thus a skin factor of 7 to 8 correspond to a flow capacity that has been divided by two.

A skin factor of 14 to 16 means it has been reduced by two third.

On the other hand a skin factor of -3.5 to -4 (due to stimulation etc) it has been doubled.

The skin factor “S”, is often considered as the effect of plugging in the vicinity of the wellbore are as a result of numerous reasons.

Well Completion – Skin effectThe skin factor “S”, is often considered as the effect of plugging in the vicinity of the wellbore are as a result of numerous reasons.

A few of them are enumerated hereunder: Sfp – due to formation plugging

Sp – due to perforations themselves (considering only the linear law of curve of as the function of Q i.e. production rate.

St – due to the effect of turbulence in the perforations or in the immediate vicinity of the wellbore (deviation with respect to the linear law. It is worth mentioning that contrary to other terms which are independent of the flow rate, St varies with it.

Spp – due to the partial penetration effect when the formation has not been fully or completely perforated throughout its pay zone.

Sd – due to the deviation effect, which is generally negligible unless the well is considerably deviated or horizontal. It is worth mentioning that Sd is (zero or) -ve and therefore enhances production rate.

Well Completion – Skin effectThe skin factor “S”, is often considered as the effect of plugging in the vicinity of the wellbore are as a result of numerous reasons.

A few of them are enumerated hereunder: Sfp – due to formation plugging

Sp – due to perforations themselves (considering only the linear law of curve of as the function of Q i.e. production rate.

St – due to the effect of turbulence in the perforations or in the immediate vicinity of the wellbore (deviation with respect to the linear law. It is worth mentioning that contrary to other terms which are independent of the flow rate, St varies with it.

Spp – due to the partial penetration effect when the formation has not been fully or completely perforated throughout its pay zone.

Sd – due to the deviation effect, which is generally negligible unless the well is considerably deviated or horizontal. It is worth mentioning that Sd is (zero or) -ve and therefore enhances production rate.

Well Completion – Skin effectWellbore Damage or Stimulation – From the standpoint of the Well Completion wellbore damage or stimulation indicators are of practical importance.

These are several ways to quantify damage or improvement. One method uses the idea of “skin effect”. Pressure drop across the infinitesimally thin skin ΔPs, is added to the transient pressure drop in the reservoir to represent the wellbore pressure. The pressure drop across the skin can be calculated as follows:

Where,Δps= pressure drop across skin, psiB = formation volume factor, reservoir bbl/stbµ = viscosity, cps = skin factor, dimensionlessk = permeability, mdh = height, ft .

skh

qBps

2.141

Well Completion – Skin effect The value of the skin factors can vary from about –5 for a hydraulically fractured well to α for a completely plugged well.

However it is prudent to understand that the concept of skin effect is that the numerical value of the skin “s” does not directly show the degree of damage. Flow Efficiency (or Condition Ratio) describes the well’s actual flow capacity as a fraction of its capacity with no damage.

Skin factor, flow efficiency, or damage ratio can be determined from most of transient pressure techniques. Wells completed with only a part of the producing zone open – through ineffective perforating or the fact that the well was not drilled completely through the zone will appear to be damaged even if there is no physical flow restriction. Deviated holes penetrating the reservoir at an angle with no other problems will appear stimulated.

wf

swf

ideal

actual

pp

ppp

J

JFE

Role of Fines and solids in bridging and Formation Damage

Particles Φ>⅓ of pore throats, form external filter cake & are easily back produced. ⅟

Particles Φ< ⅟ 7 of pore throats, will pass thru the formation & are easily back produced. ⅟

Particles Φbetween < ⅓ & ⅟ 7 of pore throats, tend to plug ( internal filter cake ) are difficult to flow back and remove.

1. American Petroleum Institute (API) and International Organization for Standardization (ISO) have established standards for oil and gas tubing and casing. Tubing is defined as pipe with nominal diameters from 1.050” to 7” ( ISO 11 960). While casing sizes range from 4.5” to 20” and even more.

Casing and tubing are classified according to following five properties:

Steel GradeType of jointsLength rangeWall thickness (unit weight)Manner of manufacture

Casing and Tubing

Tubing StringProper selection, design, and installation of the tubing string is a critical part of completions program & Wokover.

The tubing must be sized so that production is carried out efficiently.

It has to be designed against failure from tensile forces, internal and external pressures. and corrosive actions of the fluids.

It need to be installed in pressure tight and undamaged condition.

A number of grades of steel and types are tubing connections have been developed to meet demands dictated of greater depth, pressure and pressure and medium.

API has developed specifications that met the major needs of the oil and gas industry. These API specifications and bulletins provide standard dimensions, strength an performance properties and required gauging practice to ensure complete interchangeability

Tubing String – API SpecificationsAPI has developed specifications that met the major needs of the oil and gas industry. These API specifications and bulletins provide standard dimensions, strength an performance properties and required gauging practice to ensure complete interchangeability.

A few of Standards & recommended practices are enumerated as under:

1. API Standard 5CT - Specifications for Casing, Tubing and drill pipes.

2. API 5B: Specification for Threading, Gauging , and Thread Inspection of Casing, Tubing, and Linepipe Threads

3. API Bulletin 5C2- Bulletin on Performance Properties of Casing and Tubing

4. API Bulletin 5C1- Care and Use of Casing and Tubing. It contains recommended make up torque for API connections.

5. RP 5C1 : Recommended Practice for Care and Use of Casing and Tubing.

Tubing String – API SpecificationsFluid velocities in the tubing string should be less than “ fluid erosional velocities”.

API RP 14E provides guidelines for sizing lines transporting gas and liquid in two –phase flow.

The velocity above which erosion may occur is determined by following empirical equation:

Mixture of Pipe dope and solid drilled particles

Note: Each section is ¼”. Source: Completion Page 597

Mixture of Pipe dope and solid drilled particles

Source: Well Completion String . Page 597

Maximum Brine Density for W/O Operations OperatimnsOperationsCOILED TUBING

Source : Well Completion, Page 606

Documents

Work Over & Stimulation - Mid 2 (B.tech,M.tech )