petroleum pedia

Well Testing Analysis(Introduction)

2012-03-29T08:58:00.001-07:00

Introduction to Well TestingObjectives
• List the more common objectives of well testing.
• Describe the diffusivity equation by explaining
– its purpose and applications
– assumptions made in its derivation and how it is
derived
– its form for one-dimensional radial flow.
• List, define, give the units for, and specify typical sources
for each of the variables that influence responses in a well
test.
• Compute the total compressibility for different reservoir
systems (undersaturated oil, saturated oil, gas).What Is A Well Test?
• A tool for reservoir evaluation and characterization
– Investigates a much larger volume of the reservoir
than cores or logs
– Provides estimates of
– permeability under in-situ conditions
– near-wellbore conditions
– distances to boundaries
– average pressure
How Is A Well Test Conducted?

Fundamental Concepts
• Applications and objectives of well testing
• Development of the diffusivity equation
• Definitions and sources for data used in
well testingTypes and Purposes of Well
Tests
• Pressure transient tests
– We generate and measure pressure changes with time
• Deliverability tests
– Well controlled production
• (Production Analysis)
– Use of production data for goals usually achieved by
well testingProduction data analysis
• Reservoir properties (permeability, skin
factor, fracture half-length, etc).
• Reservoir pore volume (estimated using
long-term production performance).
• Estimated ultimate recovery (EUR)—
movable fluid volumes.

Well Testing Objectives

• Define reservoir limits
• Estimate average drainage area pressure
• Diagnose productivity problems
• Characterize reservoir
• Evaluate stimulation treatment effectiveness

Drilling and Completion of Multilateral Wells

2012-03-27T15:10:00.000-07:00

MULTILATERAL

TERMINOLOGIES

Laterals are wellbores drilled from the main wellbore.

 Wellbores drilled from a horizontal lateral into the horizontal plane are branches, those drilled from horizontal lateral into the vertical plane are splays.

A multilateral well can follow different well trajectories: horizontal or deviated Junctions are the intersections of the laterals with the main wellbore or of the branches and splays with the lateral

Multilateral Completion Systems

Sperry-Sun drilling Services Company has developed two distinct completion systems for multilateral well bores which have full-open through-bore and re-entry capabilities. These systems are:

Lateral-Tie Back System, LTBS.

Retrievable Multi-Lateral System, RMLS.

British Petroleum Co. (BP), has another system that is called "SRS", Selective Re-entry System for existing casing.

This system was developed by Weatherford Services Co.

The Lateral-Tie Back System, LTBS

This system consists of six main components

1.Pre-milled casing window joint.

2.drilling whipstock..

3.Lateral liner hanger.

4.Lateral liner running tool.

5.Cementing whipstock if drill with cemented Junctions.

6.Re-entry whipstock.

Retrievable Multi-Lateral System, RMLS

The RMLS consists of four components

1.Casing window system.

2.Retrievable deflection tool (whipstock) incorporating.

3.Lateral liner transition joint.

4.Washover assembly.

Selective Re-entry System of Multilaterals

Technologies were not developed that enabled drilling
multilaterals into different producing reservoirs.

SRS is the solution for increasing
oil production and reserves
from existing wells.

Technology Advancement Multilateral (TAML)

Classified multilateral wells into seven categories (six levels with one sublevel) and provided a common language for operators and service companies to use when discussing multilateral completions.

The definitions of the TAML levels were based on the amount and type of support and functionality provided at the junction in the well where one lateral wellbore merges with the main bore or with another lateral.

Technology Advancement of Multilaterals (TAML) levels

Level 1:

is an open-hole lateral from an openhole mother bore.

There is no mechanical or hydraulic junction involved.

Carried out in consolidated formation as barefoot completions.

widely applied in the United States, Canada, Europe, and the Middle East, with up to six lateral having been drilled from mother bore.

Level 2:

main bore is cased in cemented and the lateral bore is open.

The completion is economical, allows selective production, and can be carried out in standard casing sizes.

United Arab Emirates wells have proven successful candidates for level 2.

Level 3:

the main bore is cased and cemented, and the laterals are cased but not cemented.

The lateral liner is mechanically anchored to the main bore using a liner hanger.

level 4:

both the main bore and laterals are cased and cemented to provide mechanical junction integrity.

can be simple, or they can be the basis for more complex systems such as dual packers completions, single string selective reentries and single strings with lateral entry nipples.

Level 5

Sealed junctions multilaterals
are necessary for reservoir management
and to handle complex geology in well
environments with multiple pressures,
fluids, and the rock strata.

In these cases, pressure integrity is necessary to prevent junction collapse, due to pressure drawdown.

Full hydraulic and mechanical pressure integrity at junction are achieved with completion.

Level 6:

one in which junction pressure integrity is achieved with the casing and not by cement, which is not acceptable.

The entire junction is an integral part of the main bore casing string.

The first and most widely used level 6 system is the formation junction system.

The system is run in a perforated mode as part of a standard casing or liner string, then reformed down hole using swaging technology.

Conventional drilling, completion, and cementing techniques are used to finish construction and completion of well bore

watch video

http://oiltube.blogspot.com/2012/03/drilling-and-completion-of-multilateral.html

New Strategies for Designing the Horizontal Well Profiles

2012-03-27T06:44:00.002-07:00

There are three

sections, namely:

1. Vertical section: It is drilled from sea bed (mud line) until KOP (the point where deviating or sidetracking begins).

2-Turned (Curved or angle-build) section: It is drilled from KOP to the end-of-curve (EOC). This section includes the first-build arc, the straight tangent, the second-build arc.

3. Horizontal section: It is drilled from the end of second-build arc or the end-of-curve (EOC) to the end of the proposed distance to be drilled horizontally in the pay zone, in accordance with the type of the horizontal well to be drilled.

The design of horizontal well based on three method:-

1-The simple tangent build curve method:-

The three major sections that form a horizontal well may be designed as follows:-

1-The build-radius of the first-build arc:

R=5730/B

2-Height of the first-build arc:

D1=R(sin I2-sin I1)

3-Height of the straight-tangent:

D2 = L2 Cos I2

4-Height of the second-build arc:

D3=R( Sin I3 - Sin I2).

5-The length of the first section of horizontal well = KOP

KOP = TVD – D1 - D2 - D3

6-The displacement of the first-build arc:

H1 = R ( Cos I1 - Cos I2)

7-The displacement of the straight-tangent:

H2 = L2 - Sin I2

8-The displacement of the second -build arc:

H3= R( Cos I2 - Cos I3)

9-The length of the first-build arc:

L1 =100(I2 - I1 )/B

10-The length of the second-build arc:

L3=100(I3 – I2)/B

11-The measured depth at the end of the first-build arc:

MD1 = KOP + L1

12-The measured depth at the end of the straight tangent:

MD2 = MD 1+ L2

13-The measured depth at the end of the second build arc:

MD3 =MD2 + L3

*The length of the second section =

L1 + L2 + L3 = MD3 - KOP

2-circular arc method:-

It is a special design is based where,

R=H=TVDTEP-TVDKOP

Thus. BUR may be determined as follows:

BUR=5730/R

=5730/(TVDTEP-TVDKOP )

Circular arcs are usually drilled only in areas where target entry point (TEP) and directional performance are well known

EX:-the Austin Chalk-amorphous limestone

3-Compound build curve method:-

This method have more than one planned build up rate and one or more tangent sections where, different build up rates will be designed for the upper and lower sections.

EX:-a 4°/100 ft build rate may be used in the
upper section followed by a 8°/100 ft build up rate below the tangent section.

Accordingly, the recent advance for selection of the appropriate well profile is a function of the following,

1-Vertical depth of KOP and target selection. This KOP is selected based on hole problems, casing set depths, BHA performance, ROP, . . . etc.

2-Horizontal displacement to target entry point (TEP).

3-Completion design.

4-Formation evaluation program.

5-Hole size in the reservoir.

Thus, the optimum KOP should be selected based upon the following:

1-Minimizing hole problems.

2-Minimizing the amount of hole open during directional drilling operations.

3-The planned casing set depths.

4-The performance of directional drilling assemblies within various formations.

5-The expected drilling rate within the various formations.

—

After selecting the optimum KOP, the vertical depth to the target can be determined as mentioned before. This will determine the build radius options available. These options should be refined by considering horizontal displacement to the target entry point (TEP). If the planned profile is compatible with the completion, evaluation program, and desired hole size, the profile selection is complete. If a parameter is not compatible, a design parameter must be altered or compromised, as shown in Table

Horizontal Drilling Problems

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WOB (Weight On Bit)

Conventional bit weight for efficient drilling is about 2000-5000 lbf per inch of bit diameter.

Motor assemblies are more efficient with bit weight less than rotary assemblies.

Bit weight may be increased by reducing drag and torque and by using the split assembly .

Torque and Drag

Drag is a force restricting the movement of the drill tools
in directions parallel to the well path.
Torque is the force resisting rotation movement.
Excess drag and torque cause directional-drilling problems especially in turning and horizontal sections in horizontal well.
Reducing drill string weight reduces drag and torque at high quality of mud with good chemical and physical properties that are essential.
Oil base mud should be considered for more demanding situation because its good lubricating qualities.

Hole Cleaning

A particular problem that arises in drilling horizontal wells is the difficulty of the removing the rock cuttings from the horizontal section of the well.
The source of the problem is that cuttings tend to settle in the bottom of the hole and allow mud to pass above without transporting them.
High fluid velocities and polymer muds are commonly used for efficient hole cleaning and minimizing formation damage.
Also, these can be good reason to use oil-based muds to control shale swelling.

Water Sensitive Shale

- Shale layers frequently tend to collapse in contact with fresh water This can be prevented by using oil-based drilling fluids.
- These fluids usually consist of an advent emulsions of water in diesel oil together with other additives.
- Fluids of this type have been used in the North Sea.
- Water-based muds can be inhibited to reduce the attack in water-sensitive shales by the addition of NaCl or CaCl2.
- These additives reduce the chemical activity of the water and its tendency to penetrate into the water-sensitive shale.
- Inhibited water-based muds are not as effective as oil-based muds for the protection of shales, but they are cheaper and less damaging environmentally.

Directional Control

Overcoming the force of gravity is a fundamental problem in directional and horizontal drilling.

BHA includes bits,motor,non-magnetic drill collar and MWD tool

BHA section controls the hole trajectory but does not contribute to WOB.

This section should be kept as lightweight as possible to minimize torque and drag.

Horizontal well completion

2012-03-27T05:44:00.004-07:00

the completion that can be run through a given radius of curvature will depend on

1.the radial clearance between the completion item and hole(liner size),

2. the length and flexibility of the completion,

3.the rating of the connection

Horizontal well Completion Options

1.Open hole 25%

2.Slotted Liner 55%

3.Liner with Partial Isolations 15%

4.Cemented and Perforated Liners 5%

Open hole 25%

1.This type of completion is the simplest and cheapest typed used in consolidated & competent reservoir Rock with almost no sand production.

2.It is represented 25% from total or all completions worldwide

Slotted Liner 55%

1.It is used with or without a screen

2.It is used when the reservoir is unconsolidated or loosely consolidated sands.

3.It is formed 55% from all completions worldwide and it is considered as a prevailing well completion type.

4.its main purpose

to guard against hole collapse

to provides a convenient path to insert various tools such as coiled tubing in a horizontal well

●

Liner with Partial Isolations 15%

Slotted liner in open hole with blank sections and External Casing Packer (ECP).

This is 15% of total completions worldwide.

Cemented and Perforated Liners 5%

It is expensive and used in long-radius horizontal sections or for medium-radius horizontal sections. It is formed only 5% of all completions worldwide.

Problems like difficulty of cement job or leakage of cement sheath may arise in this type

Horizontal Wells (why and advantages)

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Horizontal drilling methods(Reason and methods )

2012-03-16T14:43:00.000-07:00

The choice of drilling method depends upon:

Cost,

Well spacing and

Mechanical conditions of a vertical well bore

In addition, reservoir consideration.

BUILD RATES

Ultra-short Radius

Short Radius

Medium Radius

Long Radius

ULTRA-SHORT RADIUS

45 to 90 degrees per foot

Special equipment

Horizontal lengths of 100’ to 200’

Used in unconsolidated, heavy oil sands and soft formation.

Impossible to log the open hole section.

An ultra-short radius drain hole is drilled using endless 1¼ inch tubing.

Uses a jet under high pressure to cut the formation and advance the endless tubing.

twenty-four laterals can be drilled at the same horizon.

SHORT RADIUS

1.5 to 3 degrees per foot.

Needs special equipment

Mechanical and motor systems are available.

Typically used in sidetracking existing wells to bypass water producing or troublesome.

Bending stress and fatigue can be a problem

200’ to 1000’ horizontal section

The horizontal section can be cased with a slotted liner or left open hole.

Open hole logging capabilities are limited for the horizontal section.

MEDIUM RADIUS

The first medium radius wells were drilled in 1985

6 to 35 degrees per 100’ build rates

Uses conventional equipment

Horizontal section lengths have been drilled over 7000’ but typically 2000’ to 4000’

LONG RADIUS

2 to 6 degrees per 100’ build rates

Uses conventional equipment

Horizontal section lengths have been drilled over 10,000’ but typically 3000’ to 5000’

No problem with bending stress, fatigue or completion equipment

Build section is steerable, which means the motor can be rotated in the build section

Offshore uses long radius almost exclusively since longer departures are required before the well gets to be horizontal

Wells are more easily logged.

Directional Drilling Applications

2012-03-15T14:09:00.001-07:00

Sidetracking a Stuck Bottom hole Assembly

Multiple Sidetracks

Straighten The Hole Drilling

Multiple Wells from an Artificial Structure

Multilateral Wells Drilled From a Platform.

Drilling Multiple Sands from a Single Wellbore

Inaccessible Location

Fault Drilling

Salt Dome Drilling

Relief Well Drilling

Horizontal Drilling

Directional Concepts

2012-03-15T13:41:00.003-07:00

Dogleg

an abrupt change in direction in the wellbore, frequently resulting in the formation of a key-seat.

a sharp bend permanently put in an object such as a pipe, wire rope, or a wire rope sling.

Deflection angel > 3o/100 ft

Angle of Deflection

in directional drilling, the angle at which a well diverts from vertical

usually expressed in degrees

In vertical, being zero.

Azimuth

in directional drilling, the direction of the wellbore or of the face of a deflection tool in degrees (0 -359 ) clockwise from true north.

an arc of the horizon measured between a fixed point (such as true north) and the vertical circle passing through the center of an object.

Steering Tool

A directional survey instrument used in combination with a deflected downhole motor. It shows, on a rig floor monitor, the inclination and direction of a downhole sensing unit.

MWD+LWD

Systems and Coordinates

Depth Reference

Measured Depth (MD)

True Vertical Depth (TVD)

Inclination (Drift)

The angle (in degrees) between the local vertical (local gravity vector as indicated by a plumb bob) and the tangent to the well bore axis at a particular point.

By oilfield convention, 0° is vertical and 90° is horizontal.

Toolface

Rigsite use of the term “toolface” is often used as a shortening of the phrase “toolface orientation”. This can be expressed as a direction from North or topside of the wellbore.

Toolface Orientation is the angular measurement of the toolface of a deflection tool with respect to either North or up (highside).

Highside/Magnetic Toolface

Highside Toolface

indicates whether a component is facing up, down, to the left or right

Magnetic Toolface

an angular measurement from North

Mag TFO = Azimuth + Highside

Azimuth (Hole Direction)

the direction of the borehole on the horizontal plane, measured as a clockwise angle (0°- 360°) from the North reference.

All magnetic tools give readings referenced to Magnetic North; however, the final calculated coordinates are referenced to True North

Quadrant Bearings

the directions are expressed in degrees from 0°to 90° measured from North in the two Northern quadrants and from the South in the Southern quadrants, e.g., N87°E, S12°W, S90°W.

Direction Measurement

Azimuth Reference

Quadrant Bearings

Properties of mud

2012-03-13T16:22:00.000-07:00

Properties of mud

Plastic Viscosity (PV)

•Control the magnitude of shear stress develops as one layer of fluid slides over another.

•Measure of friction between layers.

• Provides a scale of the fluid thickness.

• Decreases with increasing temperature; with liquids; the reverse with gasses .

•Effective viscosity depends on fluid velocity flow pattern, difficult to measure, but can be calculated.

• PV is the difference between readings at 600 rpm and that at 300 rpm

yield point

•A measure of the attractive forces between particles due to positive and negative charges

• Measure the forces causes mud to gel in case of motionless

•Shows a minimum level of stress must be provided before mud flows

•Expressed in lb/lOOft2

•A parameter of the Bingham plastic model. YP is the yield stress extrapolated to a shear rate of zero

•It can be increased by Bentonite .

Gel strength

•Ability of mud to develop gel structure .

•Defines the ability of mud to held solids and measures thixotropy

• Is Determined using viscometer .

• The sample stirred at high speed and the allowed to rest for 10 sec or 10 m.

•The torque readings at 300 rpm is taken as gel strength at specified time.

• Expressed in lb/100 ft2 .

•Converted to metric by multiplying by 0.478 .

Filtration and filter cake

• Filtrate is the liquid that passes through the porous and permeable rock medium, leaving the cake on the medium .

• A layer of solids deposited on the rock is described as filter cake

• Loss occur when mud pressure is higher than formation pressure

•Quantity of mud loss depends on volume of filtrate and thickness and strength of filter cake, and differential pressure .

•Ideal mud gives small filter loss and thin and tough mud cake

•Filtrate is a disadvantage due to formation damage & plugging pores by shale swelling .

•Mud cake is an advantage due to stabilizing the well bore but when increasing it decreases the hole diameter

•Polymers are used in mud cake .

•Drilling muds are tested to determine filtration rate and filter-cake properties.

• Cake properties such as cake thickness, toughness, slickness and permeability are important because the cake that forms on permeable zones in the wellbore can cause stuck pipe and other drilling problems.

•Reduced oil and gas production can result from reservoir

damage when a poor filter cake allows deep filtrate invasion.

• Can be determined by filter press, called API filter press

pH of mud

•Describe the acidity or alkalinity of mud

•Defined as the negative logarithm of the hydrogen ion (H)

•Measured by pH meter or strips or dyes

Emulsion mud

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Emulsion mud

•Water is a continuous (normal oil 5-10% by volume)

•Formulated by using sodium soap as emulsifier

•Oil is added to

increase penetration rate:oil mud allows to drill faster than watermud

• reduce filter loss,

•improve lubricity,

• reduce lost circulation

•reduce torque and drag in directional well

•The stability of emulsion mud is very important to insure best performance.

The degree of stability of a certain emulsion can be measured by several observations. The resistance of an emulsion to conduct electric current (or the breakdown voltage) is one of the important measurements which determine emulsion stability. Also filtration loss and mud viscosity are often considered measures of mud stability.

•The oil soluble polymers in a form of a gel, according to the instant invention, allow a good thermal stability and avoid any rheological contribution. They may be used at high temperature and high pressure conditions.

oil base mud

2012-03-13T16:10:00.000-07:00

oil base mud

•Water in oil emulsion

•Diesel or crude oil forms its continuous phase

•Sometimes called invert emulsion

•Water droplets are emulsified in oil

•Water is used for gel strength and barite content

•Soaps are used as emulsifiers

•Soups are made from monovalent ion (Na+) or divalent ion

•(Ca++)

•The soap molecule bridge together oil and water interfaces

•Agitation is required to break the water into small droplets

•Oil/water ratio determine the final properties

Oil-based muds generally use hydrocarbon oil as the main liquid component with other materials such as clays or colloidal asphalts added to provide the desired viscosity together with emulsifiers, polymers and other additives including weighting agents. Water may also be present, but in an amount not usually greater than 50 volume percent of the entire composition. If more than about 5% volume water is present, the mud is often referred to as an invert emulsion, i.e., water-in-oil emulsion

ADVANTAGES:

(1) performs all the functions of a water-base mud or permits an acceptable

substitute for these functions;

(2) has most of the desirable properties of a water-base mud;

(3) does not hydrate and disperse cuttings;

(4) will not dissolve salt or other water-soluble formation deposits and can be

used to core such sections

(5)exhibits good penetration rates

(6) protects productive horizons

(7) does not increase the interstitial water of cores; and

(8) is not affected by contaminants such as cement, anhydrite, salt or shale, and

can tolerate contamination with water and raw crude.

Higher oil water increases resistance to contamination and

temperature stability

Used to drill hole with severe stability

More stable at high temperature

An excellent to drill pay zone; reduce formation damage and

preserve original permeability

Disadvantages:

• Contaminate the environment

• Flammability hazards

• Difficult removal of drilled solids due to high plastic PV

• Difficult electric logging

Water base mud

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Water base mud

Consists of:

1-Liquid water, continuous phase

2-Reactive solids, for viscosity and yield point

3-Inert solids, for density

4- Chemical additives, to control properties

Hydration of clays

•Clays with high cation exchange capacity exchange large amount of water into the exchangeable layer and adsorb water onto the outer surface of plates

•This effect gives high viscosity and high yield point

•Adsorption of water causes a very sticking expansion of clay

•Overall hydration transform clay from dry power to plastic slurry

•Clay yield depends on: purity, nature of atoms in exchangeable layers and salinity of water

Bentonite and attaplugite

•Bentonite consists primarily of montmorillonite

•Came from French town Montmorillon, where first mined 1874

•Basic structure is close to pyrophllite.

•There are a small number of exchangeable ions, sodium calcium and magnesium

•Most common bentonite are those with sodium and calcium as exchangeable ions

•Attapulgite belongs to a different family of clay minerals

•Instead crystallizing as platy crystals, it forms needle like crystals

•Have excellent viscosity and yield strength when mixed with salt water

•Disadvantage is suffering high water loss and poor sealing properties

Dispersion, flocculation and defloccullation

•Agitating of clay suspension in water gives three modes: edge to edge; face to edge; and face to face

•Dispersion occurs with no face or edge association

•It results in increase in viscosity and gel strength

•Aggregate occurs with face to face association

•Aggregate results in a decrease in viscosity and gel strength

•Flocculation occurs with face to edge association

•It causes excessive gelation

•Flocculation can be broken by chemical thinners

•The resulting suspension is called deflocculated

Inert solids

•Include low gravity and high gravity

•Low gravity include sand and chert

•High gravity are added to increase mud weight or density

• Referred to as weighting materials

•Mud named as weighted mud, they are:

1)Barite (barium sulphate, BaSO4) sp.gr. 4.2

Used to prepare mud in excess of 10 ppg

Refened to as weighting agent for low cost and high purity

2)Lead sulphides (galena) sp.gr. 6.5-7.0

• Allowing mud weight up to 35 ppg

•Iron ores, sp. gr. 5+ More erosive

• Contain toxic materials

Drilling Fluids Functions

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–They

1-Cool the drill bit and lubricate its teeth
2-Lubricate and cool drill string
3-Control formation the pressure
4-Carry cutting to the surface
5-Stabilize the well bore
6-Help in the well logs
7-limitting corrosion

1-Cool bit and lubricate its teeth

•Drilling action requires mechanical energy in form of weight on bit, rotation and hydraulic energy

•Large part of energy dissipated as heat

•A Heat must be removed to allow drilling

•Mud helps remove heat

•Mud helps remove cutting between the teeth and prevent bit balling

2-Cool and lubricate drill string

•Rotating drill string generates heat

•Mud help dissipate heat from hole

•Mud absorbs heat by convection and release it by radiation

•Mud lubricate drill string and reduce friction

3-Control formation pressure

•For safe drilling, high formation pressures must be contained within the hole to

prevent damage and injury

•This achieved by hydrostatic pressure of mud

•Mud pressure should be higher than formation pressure

•An overbalance of 100-200 psi is used

•Pressure overbalance id referred as chip hold down pressure

(CHDP)

•Penetration rate decreases as CHDP increases

•For abnormal pressure CHDP becomes negative and kick will happen

4-Carry cutting to surface

•Cutting generated by the bit must be removed

•Drilling mud carries cutting form bottom to surface

•A Carrying capacity depend on annular velocity, plastic viscosity and yield

point of mud and slip velocity of generated cutting For power law fluid

5- Stabilize the wellbore

•Good mud cake stabilize the hole

•Differential pressure between mud and formation keep hole stable

•Reduce drilling time also help keep hole stable

6-Help in the evaluation

and interpretation of the well logs

•During logging mud fill the hole

•Logs used to detect hydrocarbon, measure porosity, formation ,pressure

•Mud should posses properties that help evaluate these properties

•Water base -mud is better for electric logging

7-Limiting corrosion

•The drilling fluid in most cases will have water which contain dissolved salts

•This serves as a medium for corrosion

•Precautions should be taken to prevent damage of the equipment

•Mud containing oil as the continuous phase may decrease

or prevent corrosion completely

Perforation (6)(SAFETY PROCEDURES)

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2.7. GENERAL SAFETY PROCEDURES

The following comments are applicable to both TCP and wireline conveyed methods.

Additional comments are given in section specific to wireline conveyed perforating.

a) All perforating operations, since they involve the handling and use of explosives and possibly radioactive materials, require special safety procedures to be strictly observed at all times.

b) Perforating operations should be carried out strictly according to the safety policies of Eni-Agip and the perforating Contractor. In the event of any inconsistency between policies, the most conservative policy will apply.

a) Operations involving the use of explosives shall only be performed by

Contractor’s specialized personnel responsible for perforation and similar operations. The number of persons involved shall be as low as possible.

b) Only perforating Contractor’s personnel are allowed to remain in the hazardous area (gangway, rig floor etc.) during arming of guns. The number of personnel should be limited when the guns are within 500ft of surface when tripping in and out of the hole.

c) Any operation involving the use of explosives is not allowed in the presence of thunder, lighting and thick fog, as these are sources of electric potential.

d) Explosives shall be kept on site for the shortest possible time, any remaining at the end of the operation shall be removed from the installation.

e) Explosives shall be stored on site in proper containers, within a confined area on the rig. Detonators shall be stored in separate boxes, in the same area as explosives.

f) Warning signs must be placed around the hazardous area where explosives are used.

g) All radio transmitters, radio beacons included, within a radius of 500ft from the well, shall be turned off, (since they may detonate blasting caps), starting from gun arming until perforating guns are 500ft below the sea bottom (similarly, when pulling guns out of hole and guns above 500 ft). All portable transmitters (both Eni-Agip’s and Contractors) shall be placed inside the Eni-Agip office and turned off to avoid accidental transmission. Avoid critical periods of perforating coinciding with arrival and take-off of helicopters.

h) Cranes and welding machines shall be put out of service starting from gun arming till gun pulling out and unloading.

i) District Office shall be advised by the Well Operations Supervisor on the estimated time of radio silence two hours before starting operations. The Radio Operator shall communicate actual timing.

j) Casing perforating can be performed during daylight or at night. However, the first series of shots must be carried out in daylight hours. Before perforating casing, the acceptable cement job quality shall be ascertained by means of CBL/VDL and/or by squeeze jobs.

k) Explosives are to be transported unarmed and clearly labeled to the site in secure and protective containers. Extreme care must be applied during loading and off-loading.

l) At the rig it is the responsibility of the Installation Manager to ensure that these precautions are taken.

2.7.1.Firing Systems for TCP Operations

It is normal practice to run the TCP guns with two firing systems, whenever possible, to improve the chance of a successful operation especially when running the guns on the bottom of a completion. A common combination is to use a tubing pressure actuated system as the primary means of detonating the TCP guns with a mechanical system as the back up. There are four main types of firing mechanisms for TCP guns. Only top down firing mechanisms should be used for safety when arming the guns. The operation of each firing mechanism is:

2.7.2. Tubing Pressure Activated

The guns are fired by pressuring up the test string and then bleeding off the pressure immediately. A time delay device is incorporated to allow time to bleed off. This device can be either hydraulic or a slow burning fuse. Some of the firing heads for this system are wireline retrievable which gives another back up option. However, this would preclude the

use of the drop bar system as a back up. Although this technique could be expensive on nitrogen, it is well suited to the use of a nitrogen cushion but the time delay on the system will have to be increased to allow time for the nitrogen cushion to be bled off.

2.7.3. Mechanical Impact

The TCP guns are detonated by the mechanical impact of a firing bar, which for safety must be run on wireline. (This system is colloquially known as the drop bar system.) Since the system can be affected by debris in the tubing, the completion fluid must be kept clean. The system is preferred as a back up instead of the primary firing mechanism because of the need to use wireline.

2.7.4.Electrically Activated

With this system, the guns are fired with an electrically-initiated detonator which must be run on a logging cable. Therefore the pressure control system must be rigged up. Since an inductive or wet electrical connection must be made at the firing head, the system is also susceptible to debris. This system is rarely used on well tests as the only is that the firing heads for this system are wireline retrievable, hence the guns can be run unarmed and, in the case of a misfire, the firing head can be recovered on wireline to determine the cause of the misfire.

2.7.5. Retrievable Slick line Firing Head

This type of head was primarily designed to overcome the concerns over about the possibility of guns being denoted by stray pressure or tools/debris/unnamed articles which could fall down through the tubing string and force the detonating pin into the initiator. With this type of head, this possible problem has been completely eliminated due to the design of the system. The guns are run in the hole without the firing head. Then, when ready to arm the guns, the head is run to depth on slick line and latched on to the firing stem or stinger. This system

provides its own back-up in that if the firing head does not work, it can be retrieved and a replacement run.

Retrievable firing heads are available with mechanical, hydraulic or electric triggering.

Safety

Working with explosives is one of the most dangerous professions. While working with explosives you must concentrate on what you are doing. You must perform each step carefully and correctly. Because when shortcuts are taken, when concentration is broken, when communication fails, when respect for explosives is ignored, when instructions in the book are ignored, accidents can happen and they do happen.

Safe operating practices are critical to the long-term success of perforating.

Any deviation from these procedures can put lives and properties in danger. If precautions are not taken, the danger of premature detonation may occur!

Oil and gas are our main sources of energy and in all probability will be for a long time. The oil and gas industry is involved in finding and exploiting underground deposits of oil and gas in addition maintenance of the equipment used to provide a passage for hydrocarbon to flow from reservoir to the surface is also critical.

Due to the nature of work involved, hazards typical to the oil and gas industry operations exist. Therefore, in the oil and gas industry work and safety must go hand –In -hand.

Safety measurement includes:

Properly designed, constructed and tested equipment

Well-trained, highly qualified personnel

All perforating crew members receive training on the characteristics of the explosives they use and proper techniques for handling and transporting these explosives .perforating engineers and technicians also need to be proficient in the specialized process of gun arming and disarming. They should thoroughly understand procedures and applicable local regulations. In addition, only the engineer or technicians is permitted to arm or disarm the perforating guns on a perforating job.

perforation (5)(WIRELINE DEPTH CONTROL)

2012-03-08T05:29:00.003-08:00

WIRELINE DEPTH CONTROL

Depth control for perforating is almost universally obtained through radioactivity instruments run in the cased hole in conjunction with the Casing Collar Locator (CCL). The Gamma Ray Log is generally used (Figure B28) though, in some cases, the Neutron Log or both Gamma Ray and Neutron are run. Accurate correlation of radioactivity logs with open hole logs establishes the position of casing collars with respect to the formation to be perforated. A short sub in the casing string is highly desirable to eliminate ambiguities with CCL identification, particularly when all joints of casing are about the same length. If the depth control log is made on a separate trip in the well, the proper shooting depth is determined on the perforating run by recording a second collar log with the collar locator attached to the perforator.

2.6.1.1. Gun-Gamma Ray Tool

If the combination Gun-Gamma Ray Tool is used, the entire equipment for depth control and perforating is run on a single trip in the well. The Gun-Gamma Ray Tool includes a rugged, shock proof gamma ray detector. A casing collar locator and a perforating gun can all run together. This offers greater assurance of accuracy and considerable saving of rig time. Depth control should always be used to accurately position TCP guns. A reference radioactive collar is run in the work string and its distance from the top shot is measured. Once on bottom, a through-tubing GR/CCL log is run and compared to open hole logs to establish how guns should be moved for exact positioning opposite the target formation. A variation of this procedure has been used from floating vessels in sand control completions. A sump packer is positioned and set with a wireline and becomes the locating device. The TCP gun string then is run with a locator and collet assembly on bottom. The distance from bottom gun shot to the collet latch is selected to place guns on depth. A radioactive collar should still be run to allow adjustment by logging in case of pipe tally discrepancies or slippage of the sump packer downhole.

2.6.2.2. Precision Identified Perforations

P.I.P. tags are used to provide a record of the position of perforations with respect to casing collars and/or formation boundaries. Special shaped charges fired at top and bottom of the perforated section leave traces of radioactive material within the perforations. The top and bottom perforations are then identified by sharp peaks on a Gamma Ray curve after perforating. Small size, low activity and short half-life of radioactive material used in the special charges prevent significant contamination of produced fluid. When run with Gun-Gamma Ray tool and Hollow Carrier perforators, no additional rig time is required other than that needed to log through the perforated interval.

2.6.2. TCP DEPTH CONTROL

Four main techniques are used to ensure that the guns are at the correct perforating depth:

- Running a through-tubing gamma ray collar locator to locate a reference point in the string and tie into openhole logs.

- Setting the packer on wireline at a known depth, and stinging through the guns and completion string.

- Setting the packer and guns on wireline at a known depth, and stabbing the completion string in the packer.

- Tagging a fixed and accurate reference point such as a bridge plug. The first method is the most accurate. It relies on a radioactive marker sub in the string, and the distance from the radioactive marker sub to the top shot being precisely measured at surface. The string is run in the hole to approximately the correct depth and a short section of GRCCL (Gamma Ray-Casing Collar Locator) log is run over the zone where the sub is located. The gamma ray log indicates the position of the sub (a short radioactive peak anomaly) relative to the formation gamma ray as shown in Figure B30. As the distance from the sub to the top shot is known, the position of the guns can be calculated, and corrected if necessary by spacing out the string at surface. After the packer is set, the gamma ray may be rerun to ensure that the guns are at the correct depth. Fig. B30: TCP Depth Control Log.

As the cased hole gamma ray log can be considerably attenuated, a low logging speed will achieve better correlation results between the cased hole and the open hole gamma ray logs. If the formation gamma ray curve does not show much activity, a radioactive pip tag may be placed in or below one casing joint. (Placement of the pip tag must be included in the casing setting program.) Alternatively, a TDT or a neutron log can be run in place of the gamma ray log.

Perforation (3) (Explosives Classifications)

2012-03-08T05:03:00.000-08:00

Explosives Classifications

Explosives were invented first by the Chinese in the 10th century, then independently by the Arabs in the 13th century. The low explosive, or black powder, was characterized by slow reaction rates, 500 to 1500 m/sec, and relatively low combustion pressure. Much later, in 1846, the first high explosive was discovered by an Italian, Ascanio Sobreto, and then made commercially by Alfred Nobel in 1867 with the development of dynamite, a combination of nitroglycerin and clayey earth. High explosives, unlike the earlier low explosives, detonate at very rapid rates of 5000 to 9000 m/sec and generate tremendous combustion pressures. The terms low and high explosive are still used to characterize chemical explosives.

2.4.1.Low explosives (propellants)

Are used in modern oilfield applications as power charges for pressure setting assemblies, bullet perforators and sample taker guns as well as for stimulation (high-energy gas fracturing, perf wash, etc.). High explosives are found in shaped charges, the detonating cord and detonators, and blasting caps.

2.4.2.High explosives

are further classified by their sensitivity or ease of detonation.

2.4.2.1. Primary high explosives
are very sensitive and easily detonated by shock, friction or heat. For safety reasons, primary high explosives, such as lead azide, are used only in electrical or percussion detonators in Schlumberger gun systems.

2.4.2.2. Secondary high explosives

are less sensitive and require a high-energy shock wave to initiate detonation (usually provided by a primary high explosive). Secondary high explosives are used in all other elements of the ballistic chain (detonating cord, boosters and shaped charges). PETN, RDX, HMX and HNS are secondary high explosives used in oilwell perforating. The rate of reaction, combustion pressure and sensitivity of chemical explosives are affected by temperature. Consequently, maximum safe operating temperatures are defined for all explosives. Exceeding temperature ratings may result in autodetonation or reduced performance. The table below lists the 1- and 100-hr temperature ratings and uses for the various explosives in gun systems.

2.4.3. Effect of temperature

Temperature affects the rate of reaction, combustion pressure and sensitivity of chemical explosives. Consequently, maximum safe operating temperatures are defined for all explosives. Exceeding the optimum temperature rating may result in autodetonation or reduced performance.

The table lists the 1-hr and 100-hrtemperature ratings and uses for the various explosives in schlumberger gun systems.

perforation(2) (Detonators)(guns)

2012-03-08T05:00:00.001-08:00

Detonators

Perforating guns carry explosive charges to the borehole where they are detonated creating cylindrical holes in the casing and the cement. This allows oil and gas to flow from the formation into the well.

The critical parts of the perforating guns are:

· Detonating cord

· Detonators

Detonators are divided into two main types:

· Electrical detonators

· Percussion detonators

Electrical detonators are known as blasting caps and are typically used in wireline operations.

Percussion detonators are generally used with tubing conveyed, coil tubing conveyedd and non-electric wireline systems

2.3.4.3. The S.A.F.E system

There are numerous safeguards implemented in both the electrical and percussion detonation systems. However, these conventional systems may explode accidentally when exposed to electric magnetic fields or other voltages found around the field.

The S.A.F.E. Slapper-Actuated Firing Equipment system was developed to be immune from the potential differences created by the radio-frequency(RF) radiation, impressed current from corrosion cathodic protection, electric welding, high-tension power lines and induction motors such as top drives on drilling rigs.

S.A.F.E. equipment is available for most types of perforating / explosive assemblies run on wireline .

2.3.4.4. Key components of the safe system

The S.A.F.E. system initiates a gun firing without the use of any primary detonating material.

The key components of the S.A.F.E. System are the EFI or exploding foil initiator and the ESIC or the electrical secondary explosive initiating cartridge. The ESIC generates a unique signature of high voltage and current and rapidly discharges the pulse. The pulse is necessary to fire the EFI.

2.3.4.5.Operation mechanism of the S.A.F.E SYSTEM

Let's now look at the detailed operation mechanism of the S.A.F.E system. Here we see an internal view of the EFI with the components identified

2.3.4.6.Secure Detonator

The secure detonator is a third-generation on S.A.F.E type device that also uses an EFI. it does not contain primary high explosives or a down-hole electronic cartridge. A microcircuit performs the same function as the electronic cartridge and EFI together in a package. It is similar in size to a conventional electric detonator. The secure system has all the technical advantage of S.A.F.E detonator, but is more reliable and fully expandable. It is also smaller in size and therefore allows the gun strings to be shorter.

Both secure and safe system fire using high voltage and current. Their electronic circuits are protected and they don't fire accidentally in case of malfunction.

2.3.5. Casing guns

Casing guns are a type of carriers. Traditionally, casing guns were run on wireline to perforate wells before completion is run.

There are two types of casing guns:

· Reusable-carrier Port Plug Gun (PPG)

· Expandable High-Efficiency Gun System (HEGS)

Both types of casing guns are fully retrievable.

Casing guns are designed as systems comprising specific carriers, detonating cords and boosters to provide maximum perforator performance. To ensure the performance meets design specifications, charges are quality control-tested during production in actual gun carriers.

Loaded casing guns contain only secondary high explosives (detonating cords, boosters and charges), allowing safe transport and handling when safety procedures are being observed.

2.3.6. Parameters of gun selection

After deciding to use wireline casing guns in the completion, the selection of the most appropriate gun depends on several parameters. These are:

· Casing internal diameter

· Bottomhole temperature and pressure

· Deep penetrator or big hole application

· Required shot phasing and density

· Perforator performance and value

2.3.7. High shot density guns

High Shot Density (HSD) guns are another type of carrier guns. They comprise of specific carriers, charges, detonating cords and boosters to provide maximum perforator performance. HSD guns provide increased shot available for natural, stimulated or sand control completions.

HSD are the most flexible guns in the field. They are expandable, retrievable carriers and can be run on any type of conveyance (tubing, completion, slick line, TCP, wireline, coil tubing, etc.)

HSD gun features:

· Expandable carriers

· Shot density

· Helical shot pattern

· Automatic ballistic connection

· Firing modes

· Mechanical connections

· Exclusive use of secondary explosives

· Quality assured

HSD perforating guns incorporate shaped charges, detonating cord and detonators. Standard operating procedures must be followed when loading or running these gun systems. Loaded guns should be enclosed in protective tubes during storage to protect the exposed explosives.

Three critical tests are performed on HSD perforating guns for reliability testing. These are:

· Mechanical / Pressure / Temperature test

· Perforating gun Split / Swill test

· Drop Test

2.3.8. Through-tubing Guns

Through-tubing guns are used primarily for underbalanced initial or subsequent completions that have the tubing and bottomhole assembly already in place. Optimal underbalance can be applied to achieve clean, productive perforations while maintaining absolute well control.

The through-tubing guns are designed as systems comprising of specific carriers, charges, detonating cords and boosters to provide maximum perforating performance.

Loaded through-tubing guns contain only secondary high explosives (detonating cords, boosters and charges), allowing safe transport and handling when standard safety procedures are being observed.

Through-tubing guns include:

1. The hollow carrier guns

2. The exposed guns

Types of hollow carrier guns

They include Scallop gun systems .these guns are fully retrievable and are the most rigged through-tubing guns, capable of withstanding the highest temperatures and pressures .the hollow carrier guns can be run at very high speeds .enerjet gun are wireline conveyed ,capsule charge -type ,perforating guns in the enerjet gun systems each shaped charge is encapsuled and loaded on a strip carrier rather than being enclosed in a hollow tube carrier.

This permits larger charges for the same overall gun diameter .Also, due to the greater charge size; enerjet guns outperform hollow carrier guns of the same diameter.

enrjet guns are classified into two main types

1.with retrievable carriers

2.fully expendable carriers

The retrievable system is designed for rugged conveyance while running down-hole .it provides shot verification.any charge that does not retrived from the well along with the carrier strip .as the carrier is retrieved there is less debris in the well. Expendable systems are useful for applications where well components or conditions make the retrievable of the carrier strip difficult after the gun is shot.

Perforation(1)

2012-03-08T04:47:00.000-08:00

Overview

             Perforating is a critical part of any well completion process.
             The perforating process generates holes -perforation tunnels- in
       steel casing surrounding cement and the formation.

In the past, perforation was regarded simply as holes in steel casing made .

                       By different methods. But perforation is not just a simple
   hole drilling process.Perforated completions play a crucial
   role in economic oil and gas production.

Long term well productivity and efficient hydrocarbon recovery.

2.2. History of Perforation in Brief

       1.      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.

2. Bullet perforating equipment was developed in the early
1930's and has been in continuous and widespread use since that time.

-The major drawbacks with this   method were that the bullet
   remained in the perforation tunnel, penetration was not very good,
   and some casings could not be perforated effectively.

3. 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 fo 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.

2.3. Gun systems

2.3.1. Overview

In order to allow oil and gas to flow into the well, conduits
need to be made into the formation. To do this, a gun is
positioned across the producing formation and is detonated
to create perforations through the casing and cement.
The guns used for this purpose are known as perforating guns.

2.3.2. Perforating guns are divided into two primary categories:

· Capsule guns

· Carrier guns

2.3.3. The perforating gun performance is affected by the

· Gun size

· Clearance

· Entrance hole diameter

· Shot density

· Gun phasing

· Perforating length

· Temperature rating

After firing the gun and while retrieving, unwanted solids enter
into the wellbore or formation through perforating tunnels.
These are called the perforating debris. Perforating debris
can create problems in highly deviated or horizontal wellbores
and can also create problems with the completion hardware.

Sources of debris are not only gun system, but also from
the casing, cement and formation.

Gun hardware contributing to debris are:

· Gun body

· Shaped charge liner slug and jet

· Shaped charge case

· Shaped charge retaining system (that holds the charge inside the gun).

2.3.4.1. Shaped charge liner

Perforating debris sources can be controlled if properly engineered.
Shape charge liner used in deep penetrating charges is made of
powder metal, which eliminates the carrot and slug associated with
liner penetration into the formation during charge detonation.

Big hole charges us solid liners in order to produce large
hole into the casing. However pf4621 power flow liners,
produce big holes and yet leave no slugs into perforating tunnels,
this new technology charge can replace the ultrapack charges.

Attempts are made to contain the debris in the gun,
collect it after perforating or minimize the quantity expelled.
To address this problem of controlling the debris,

two methods are used. These are:

· Zinc casing method

· Patented packing method

Additional techniques that contribute to reduced perforating
debris include powder metal liners and non-plastic charge retention systems.
These recent innovations help in limiting problems arising from
perforation debris.

2.3.4.1.1. SHAPED CHARGE THEORY

The ultimate goal of perforating is to provide adequate productivity.
Test laboratories evolved over the years to provide means of predicting
and improving well performance. Today, the performance of the charges
is determined according to the procedures outlined in the API RP 43
(standard procedure for evaluation of well perforators) fifth edition,
published in 1991. From Figure B1 it can be seen that the penetrating
power of a cylinder of explosive is greatly increased by a cavity at
the end opposite to the detonator. Furthermore, placing a thin metallic
liner in the cavity increases penetration. A typical shaped charge
consists of four main components: a case, a high order explosive powder,
primer and a liner, as shown in Figure shown

The case simply holds all the components together.

- The explosive (RDX, HMX and HNS) is a complex mixture
designed to allow packing and shipping in the case.

- The primer is a purer mixture of explosive which is more sensitive
to the detonation of the detonating cord.

- The liner is used to form a jet which physically does the perforating.

- The detonating cord, which is initiated by a blasting cap, detonates
each charge.
The selection of explosive material is based on the well
temperature and anticipated exposure time at that temperature (Figure B3).
RDX, HMX and HNS are all explosives used in oil well shaped charge
manufacture. For deep penetrating charges, the liner is made from a mixture
of powdered metals pressed into the shape of a cone. High precision in
the pressing operation is required and it must be done in an extremely
uniform and predictable manner. For Big Hole charges, the liner is
drawn from a solid sheet of metal into hemispherical, parabolic,
or more complex shapes.

For each of the two types of charges, there is a trade-off between
entrance hole size and penetration. The sequence of events in
firing is illustrated in Figure B4 from top to bottom.
The detonator initiates the cord which detonates at a rate
of approximately 7000 m/s (23,000 ft/sec.) The pressure impulse
from this detonation initiates the primer in the charge and the
explosive begins to detonate along the length of the charge.

The high pressure wave 30x10⁶ kPa, 4,500,000 psi) strikes
the liner and propels it inward. The liner collapses from
apex to skirt imparting momentum with a velocity approaching
2500 m/s (8000 ft/sec). At the point of impact on the axis
the pressure increases to approximately 50x106 kPa (7,000,000 psi)
and from this high pressure region, a small amount of material is
propelled out at velocities in excess of 7000 m/sec (23,000 ft/sec).

As the liner collapses further down the cone, more and more material
must be propelled by less and less explosive such that the
impact pressure is substantially less. Thus the tip of this so-called
jet is travelling 20 times faster than the rear portion and gives the
elongated shape to the jet. The penetration depth depends on this
stretching action. As the liner walls collapse inward, the resultant
collision along the axis divides the flow into two parts, as in
Figure B5. The inner surface of the liner material forms
the penetrating jet which is squirted out along the charge.
The outer surface of the liner, which was in contact with the explosive,
forms a rear jet or slug which moves forward slower than the forward jet.
In the zone of collision, where division of the material forming the jet
and slug takes place, there is a neutral point which moves along the axis
as the liner collapse process continues. The very fast jet impacting
a casing generates a pressure of approximately 70x106 kPa (10,000,000 psi).
At this pressure the steel casing flows plastically and the entrance hole is formed.

A similar behavior occurs with formation material as the jet penetrates.
In addition, crushing and compacting of the formation material around
the perforation may also occur. The entire process from detonation
to perforation completion takes from 100 to 300 microseconds.
The jet material arriving last at the target, making the end of the perforation,
comes from the skirt or base. As discrete portions of the jet strike at this
end of the hole, they penetrate, expending their energy in the process.
Portions of the jet continue the penetration process, until the entire jet is expended.
The perforation occurs so fast that, essentially, no heat is transferred.
Indeed, it has been demonstrated that a stack of telephone directories
can be penetrated without singeing a single page. It follows that no fusing
of formation material occurs during penetration. However, crushing and
compacting of formation material is to be expected, and will be reviewed later.

2.3.4.1.2. SHAPED CHARGE DESIGN

Liner aspects, such as geometry, angle, material, and distance from base to apex,
as well as stand off, and explosive density are more important than the amount
of explosive (Figure B7a). Only about 20% of the available explosive energy
goes into the useful jet. It has been proven that properly designed charges
can out perform poorly designed charges that have twice the explosive load.

This is important in situations where a higher explosive load causes
casing damage. Once a charge is designed for entrance hole and
penetration efficiency, manufacturing quality control and
consistency become significant in shaped charge performance.
Perforation efficiency is accomplished with maximum penetration,
uniform crushed zone, and minimal plugging due to slug debris.
This is achieved by designing a liner that will provide
a uniform jet diameter and velocity with little to no deviation from the conical liner axis. For example, it is critical that the liner thickness and density be precise around the cone at any given point away from the apex. Figure B7b is an example of a less desirable jet due to poor quality control

perforation (4)(Types of perforation techniques)

2012-03-07T09:07:00.000-08:00

Types of perforation techniques

2.5.1. According to the relation between
reservoir and hydrostatic pressures

2.5.1.1. overbalanced perforation

main features of overbalanced perforation

1- hydrostatic pressure of fluid in well bore greater than reservoir pressure

2- provide control over well while performing completion

3- perforation can be plugged with debris in well bore "difficult in cleaning process"

2.5.2.2. underbalanced perforation

main features of underbalanced perforation

1- Hydrostatic pressure of fluid in well bore is less than the reservoir pressure

2- Well is "Live" after perforation and must be controlled

3- Perforation will be clean from surge into well bore

2.5.2. According to where we do perforation

2.5.2.1.Shop perforated casing are classified to

- Round perforated

- Slotted perforated

In round perforated casing the diameter of slots are 1/8 to 3/8 in and it made
by milling or by oxyacetylene torch. The diameter of hole depends on the casing diameter.

In slotted perforation the slots are 0.05 to 0.3 inch wide & 1.5 to 3 inch long and it
also made by milling or by oxyacetylene torch. And we should take care that the total
area of slots equal 2% of casing area. We can also use screen to prevent sand to
enter the well. And we prefer slotted casing than rounded one in sandy formations.

2.5.2.2. Gun perforated casing:

The second type of perforation is gun perforated casing which is our main point
in our study.

Optimum perforation

Perforating is a critical part of any well completion process .
perforating is the only way to establish conductive tunnels that link oil and gas
reservoirs to steel cased well bores which lead to surface .
however perforating also damage s formation permeability around perforation tunnels .
this damage and perforation parameters like formation penetration hole size ,number
of shots and the angle between holes have a significant impact on pressure
drop near a well ,therefore, on production .optimization the perforation parameter
and mitigating induced damage are the vital aspects of perforating.
Ongoing before perforating is less than the formation pressure is essential
in removing damage and debris from perforations.

2.5.3. According to how we do perforation

There are three basic techniques employed today to perforate a well.
Although the variations are virtually endless, the following discussion
is limited to a basic description of the three techniques. Wells can be perforated
using casing guns conveyed on wire line, through-tubing guns, and
tubing-conveyed guns. Because each method has advantages and limitations,
the completion engineer must choose the most appropriate technique for each well.

2.5.2.1. WIRELINE CASING GUN TECHNIQUES

Perforating with a casing gun conveyed on wire line has been a standard
technique for many years. Before the tubing and wellhead are put in place,
a hollow carrier casing gun is lowered into the well on wire line, positioned
opposite the productive zone, and detonated. The main advantages of this
system are as follows:

- The diameter of the gun is limited only by the ID of the casing;
therefore, large, high performance shaped charges can be conveyed
in a multiphase, high shot density carrier.

- The casing gun offers high reliability because the blasting cap
detonating cord and shaped charges are protected from the wellbore
environment and the carrier is mechanically strong.

- Selective firing is available between guns.

- Guns are accurately positioned opposite the zone of interest using
a casing collar locator.

- No damage occurs to the casing and virtually no debris is left
in the well.

There are two main limitations to this method:

- As a general practice, the well must be perforated with the wellbore pressure
greater than the formation pressure. This pressure differential may prevent
optimum cleanup of the perforations. The situation is aggravated when perforating in
drilling mud. The mud plugs are difficult to remove even when subjected to high
reverse pressure. Perforating in clean liquids such as salt water is recommended.

- The strength of the wireline and the weight of the casing guns limit the length
of the assembly which can be run on each trip into the well.

There are three basic types of casing guns:

1. Port Plug Guns

2. Scalloped Guns

3. Slick Walled Guns

Each gun design has the same primary purpose to seal the guns from the wellbore
pressure and fluids. The differences are in how this is achieved and how the
individual charges are secured in place. Port Plug guns are re-usable carriers
that use the port plug to secure the charge (Figures B17 and B18). The perforating
charge has to penetrate the carrier before it can perforate the casing. Port Plug guns
are designed so that the charge perforates a port plug which can be replaced and the
gun re-used. Gun life is not indefinite but being able to distribute the carrier cost
over 10 to 15 jobs reduces the overall cost of perforating. Fig. B18: Port Plug Gun.

Scalloped guns are typically used when high shot density perforating
(greater than 4 spf, 13 spm) is required. The carrier is a metal tube
with Flat bottomed holes milled on the outside, about 3 mm deep. These
scallops are aligned with the perforating charges inside the gun so that the
charges fire through the centre of the scallop. This does not significantly
change the penetration of the charge but rather is to ensure

that any burring that may have occurred on the gun wall does not exceed
the overall gun outside diameter.

The charges are held in place by a tube or triangular strip (Figure B19)

which is slid into the gun itself. The scalloped gun is used for high shot
density because the cost of machining so many port plug holes (up to 39 per meter)
is prohibitive and the chance of a port plug leaking and flooding the guns is obviously
increased. Another common use for the scalloped carrier is for TCP work.
Whenever a TCP system is used for a permanent completion, the guns will
not be retrieved, for this case the cost of machining port plugs will not be
recovered. Fig. B20: Slick Walled Gun.

The Slick Walled guns are a unique carrier designed for a moderate environment (Figure B20).

The gun carriers have neither port plugs nor scallops. It is simply smooth surfaced
pipe through which the charges perforate. This causes some burrs on the outside
of the carrier but as long as enough clearance exists no problems will be encountered.
The carrier and explosives are rated for lower pressures and temperatures than
other gun systems (27.5 MPa, 99 degree C for 1 hour) and can only be loaded to
a maximum of 13 spm (4 spf). The charges are held in place by a moulded Styrofoam
case which allows quick efficient loading.
The system allows for cost effective perforating of shallow to medium (2500 m) depth wells

2.5.2.2. THROUGH-TUBING PERFORATING TECHNIQUE

In 1953, Humble Oil and Refining Co. pioneered the permanent-type well completion.

This technique involves setting the production tubing and wellhead in place and
then perforating the well with small diameter guns capable of running through tubing.
The main advantages of this technique are as follows:

- The well may be perforated with the wellbore pressure below the formation pressure
allowing the reservoir fluids to instantly clean up the perforating debris.

- Completion of a new zone or a workover of an existing zone does not require
the use of a rig.

- A casing collar locator allows for accurate depth positioning.

The main limitations of this method are as follows:

- To allow the gun to run through tubing, smaller shaped charges, with reduced
penetrations, must be used. To achieve maximum penetration with through tubing
perforators the gun is usually positioned against the casing to eliminate the loss
of performance when perforating through the liquid in the wellbore.
This arrangement restricts the gun to 0o phasing.

- In an effort to improve the penetration performance, gun system designers
eliminate the hollow steel carrier and place pressure tight capsule charges
on a strip or wire. These guns are called expendable or semi-expendable
depending on whether the wire or strip is retrieved. Removing the steel
carrier allows a larger charge to be used; however, charge case
debris is left in the well after perforating and the casing may be
damaged by the detonation.

- The charges are exposed in the expendable and semi-expendable systems restricting
these guns to less severe well environments and lower running speeds.

As stated earlier, these guns, designed to pass through tubing are used for a variety of reasons:

1. Critical sour gas wells where a permanent packer is to be in place before perforating occurs.

2. Older wells where a retrievable packer cannot be un-set due to failure.

3. Perforate slim casings or liners (89 mm).

The small outside diameter of through-tubing guns implies that if the charges are to
be contained inside of a tube (HSC) the explosive load will have to be small. Such
is the case with our hyper dome guns (Figure B21). With explosive weights of
1.8 gm to 6.5 gm, penetrations can be limited but exposure to wellbore fluids
and potential failure thereby is eliminated. Fig. B22: Enerjet Gun.

If deeper penetration is required, an expendable or semi-expendable carrier is required.
Because the gun outside diameter is governed by the charge size, a maximum load can
be placed down hole after passing through the tubing. Care must be taken not to attempt
too large of an explosive charge. If unenclosed charges in excess of 20 grams are
allowed to detonate downhole, casing damage could result.

Typical of these carriers is our Enerjet gun where the charges are threaded into
a steel bar (Figure B22). Explosive loads can go as high as 15.5 gms and after
detonation the steel bar and threaded caps are retrieved from the well.
In this manner only a minimum amount of debris, in the form of powder is left behind.

2.5.2TUBING-CONVEYED PERFORATING
TECHNIQUE

Although various attempts were made to convey perforating guns into
the well on tubing it was not until the early 1980's that widespread use
of the service began. The basic technique involves assembling hollow
carrier steel casing guns vertically with a firing head on top. There
are several types of firing heads including drop bar, differential pressure,
direct pressure, and electrical wet connect. On top of the firing head
is a sub used to allow reservoir fluids to flow into the tubing.
A production packer is attached above the fluid communication sub.
This entire assembly is then lowered into the well on the end of the tubing string.
The string is depth positioned usually with a gamma ray survey.

After the guns are positioned,
the packer is set, and the well is readied for production.
This includes establishing the correct underbalanced condition in the tubing.
The guns are then fired and the surge of reservoir fluids is used to clean
up the perforations. Depending on the situation the guns may be retrieved or dropped to the bottom of the well.
Many variations of the procedure described above are in use today.
The main advantages of this technique are as follows:

- The well can be perforated with large diameter, high performance;
high shot density casing guns with the wellbore pressure lower
than the formation pressure (underbalanced) allowing instantaneous cleanup of the perforations.

- The wellhead is in place and the packer is set before the guns are fired.

- Large intervals can be perforated simultaneously on one trip into the well.

- Highly deviated and horizontal wells can be perforated by pushing the guns into the well.

The main limitations of the technique are as follows:

- Unless the guns are withdrawn from the well it is difficult to confirm whether the entire
gun fired. Effective shot detection systems may overcome this limitation.

- Explosives degrade when exposed to elevated temperatures,
reducing shaped charge performance. It takes many times longer to run a TCP string into the hole than a wire line gun. To compensate, a more expensive and, in some cases, less powerful explosive must be used on TCP operations.

- Selective perforating options with TCP are limited. Small intervals over large intervals may not be economical with TCP.

- Accurate depth positioning of the gun string is more difficult and time consuming than wire line depth positioning.

2.5.2.3.1. TCP FIRING SYSTEMS

Several firing techniques are available for various types of completion or testing operations. They include percussion, pressure, and electrically activated systems.

2.5.2.3.2. Percussion-Activated Firing Head (Drop-bar)

The drop bar is the simplest TCP firing system. A cylindrical weight or sinker bar is dropped into the tubing and strikes a percussion- type detonator in the gun firing head.

Hydraulic pressure on the tubing fluid column is adjusted to achieve the desired underbalance on the formation before dropping the bar. The bar can be dropped by hand through an open wellhead control valve or contained in a wireline lubricator and released when wellhead valves are opened and can also be run on a slickline.

2.5.2.3.3. Bar Actuated Pressure Firing System

The gun is not fired by the impact of the drop bar on the firing head. Instead, the drop bar shears a pin, which releases the catch on the firing piston. The firing piston is then driven hydrostatically towards the percussion cap to set off the detonating train. A minimum hydrostatic head of 500 psi is needed in the tubing to set the gun off. With this feature, it is not possible to accidentally fire the gun at surface by dropping anything on the firing head. If the well is perforated dry, the 500 psi required can be obtained by pressuring the tubing with nitrogen prior to dropping the bar.

2.5.2.3.4. Differential-Pressure Firing Head

The differential-pressure firing head utilizes a flowtube through the packer to transfer annulus pressure above the packer to an isolated piston in the firing head located beneath the packer. The advantage of this firing method is that, after setting the packer, the tubing and packer can be tested in the direction of well pressure by internally pressuring the tubing and transmitting this pressure to casing beneath. After Pressure testing, the desired underbalance pressure is fixed before firing the guns. The annulus pressure forces the release piston downward, breaking the shear pins and releasing the locking lugs which secure the firing pin. The hydrostatic pressure in the rathole below the packer then drives the firing pin into the percussion cap, igniting the Primacord which fires the perforating guns.

2.5.2.3.5. Tubing - Pressure Firing System

This system uses a percussion-activated firing head similar in principle to the differential pressure and drop-bar systems, except that it is activated by internally pressuring the tubing. This same system is used, without modification, for DST’s or permanent completions. After setting the packer, it is tested by pressuring the tubing annulus. Next, the tubing pressure is raised through three specific pressure cycles to arm the gun. Two of these are redundant safety cycles built into the system to account for unanticipated excursions such as high pressure surges, swab pressures, and high circulating pressures. After the three cycle sequence, there is a variable time delay before firing in order to correct underbalanced pressure and adjust wellhead choke manifolds.

An advantage of the tubing-pressure system is that it can be fired in wells where the casing above the packer is leaking; e.g., split or corroded pipe and old squeeze perforations.

2.5.2.3.6. Electric - Wire line Firing System

The electric-wire line firing system uses electric current and logging cable for firing. Conventional wire line pressure-control equipment (lubricator, blowout preventer, etc.) is used during flow testing with cable in the hole. The wet connector contains a mechanical latch that secures it to the TCP firing head, preventing the cable from being blown uphole. With these firing systems, an electric current transmitted to a wet connector at the gun head fires the detonator. One of the major advantages of these systems is that they cannot be inadvertently armed and fired before the electric power source is connected with the firing head. A gamma ray and collar log can be run with the electric-wire line firing system.

2.5.2.3.7. JOB PLANNING AND OPERATIONAL CONSIDERATIONS FOR TCP

Personnel safety is one of our highest concerns; Schlumberger requires the use of a minimum three meter safety spacer above the gun. This ensures that the guns are below the rig floor when the firing head is connected. Cleanliness is the most important factor governing success or failure of a TCP operation. A dirty workstring with pipe scale, dope, or gelled mud with high solids content can prevent access to any of the firing head systems. Any workstring (new or used) should always be rattled or washed clean before picking up the TCP assembly. Pipe dope should be used sparingly. Once on bottom, circulation should be established to flush trash through the circulating sub. A joint of tubing filled with clean fluid should be run immediately below the circulating sub. If the TCP assembly contains a closed annular production valve and the workstring is filled on the floor with clean brine or diesel while going in hole, circulation is not necessary. In high-angle holes the drop bar should not be used, and pressure-type firing systems are recommended. Gun release subs should be used with permanent completions to allow production logging and access to perforations for remedial stimulation work. If sufficient casing rathole is not available to accommodate the fired guns, they can be pulled out of the well if a stabthrough TCP arrangement is used with a larger bore packer. However, this is not desirable since the well will have to be killed and equipment pulled and rerun. Such a system would likely require guns with smaller OD’s. The optimum underbalance pressure is dependent upon several factors such as perforation size and length, rock strength, reservoir permeability, and fluid viscosity. All of these, in theory, affect the ability of the perforation to be cleaned. As a practical matter, the underbalance pressure should be between a minimum of a few hundred pounds per square inch and a maximum of the design collapse rating for the casing. Low-permeability formations and zones producing gas require larger pressure differentials to clean up the perforations.

Some of the most common TCP accessories are listed on the following pages.

2.5.2.3.7.1. Radioactive Marker Sub

The sub is run in line with the workstring above the packer, or can simply be a tubing collar or a drill pipe tool joint where one or two small cavities have been drilled and threaded to receive a sealing plug. A radioactive pip tag is installed in each cavity. A pip tag is a very weak gamma ray source (1 microcurie of Cobalt 60). The radiocative marker sub is run above the packer, and all the radioactive material is fully recovered when the string is pulled (Figure B23).

2.5.2.3.7.2.Cone-Type Debris Circulating Sub

The debris circulating sub (Figure B24) consists of a ceramic cone seated into a ported sub. The sub is positioned between the packer and the guns, typically 10 m above the firing head. The isolated space below the sub is filled with a clean fluid. Once the assembly above the sub has been circulated clean, the packer is set. A debris circulating sub is often used with a drop bar or a wet connected firing system to prevent debris from settling on the downhole portion of the firing head. The drop

bar or female wet connector will easily break the fragile cone to reach the firing head.

Fig. B23: Radioactive Marker Sub. Fig. B24: Debris Sub.

2.5.2.3.7.3.Mechanical Gun Release Sub

The operating principle of the mechanical gun release sub (Figure B25) is similar to other gun release subs. After a release sleeve is shifted, the lower sub locking fingers retract. The lower sub and the gun string are then released and fall to the bottom of the well. Fig. B25: Gun Release Sub. Fig. B26: Surge-Disc Sub

2.5.2.3.7.4. Surge-Disc Sub

The surge-disc sub (Figure B26) features a fragile, high strength, sealed, glass disc inside a sub. The disc is designed to withstand a high differential pressure.

The sub is positioned above the circulating sub, completely sealing off the portion of tubing above it. This portion of tubing can be dry or partially filled with a clean fluid cushion to create an underbalance condition after the packer is set and the disc broken. In the presence of old perforations, the sub can be used with a drop bar firing system. In this application, the underbalance will be established a few seconds before firing the guns. The underbalance will remain effective during firing and at the time of the surge immediately after firing.

2.5.2.4. COILED TUBING CONVEYED PERFORATING FOR HORIZONTAL WELLS

2.5.2.4.1. Principle

The principle of this system (Figure B27) is particularly simple: the guns are mounted directly on the end of tubing coiled on a reel in which the electric cable has first been inserted. The connection between guns and tubing ensures the mechanical and electrical bottom link, while on the surface; the cable outlet passes through the shaft of the drum by a rotating device. The lowering and raising movements are provided by the standard coiled-tubing injector head, and the depth measurements are made on the tubing near the injector. This technique is equally capable of conveying small-diameter guns and standard guns, but the performance capabilities will be affected by gun weight. In addition, circulation through the coiled tubing remains available, although the cross section is reduced, owing to the cable.

2.5.2.4.2. Procedure

The logging procedure with this system is exactly the same as that for normal use of coiled tubing. Should it be necessary to work under pressure, a lubricator adapted to the guns should be added. The weak link in this system is its relative fragility, rendering it incapable for pushing heavy guns over great distances. Fig. B28: Perforating Depth Control.

Well completion

2012-03-07T07:48:00.000-08:00

Well completion

Do you think a well is ready for production as soon as it's drilled?

Well completion is the phase that comes after the drilling of
a well but before the well is used for production.
The process of well completion involves a group of operation
that extends beyond simply installing well bore
tubular & well completion equipment.
In fact the well completion process includes:

1- installing & cementing

2- running production tubing

3- Perforating a well

4- cleaning up or testing

Occasionally the completion design can be affected by factors
such as a complex
wellhead or any processing storage requirements
affecting productivity.

Completion engineers used 2 main industrial terminologies:

1- lower completion for the part across reservoir
sand face that includes perforation,
flow control valves & permanent monitoring

2- Upper completion for part above packers' assembly that
includes safety valves, gas lift mandrels,
tubing & wellheads.

There are 3 basic requirements that any well completion must meet.

A well completion system must be

1- efficient in terms of meeting all the production objectives

2- safe in terms of a secure well environment

3- economic in terms of the profit generated over the cost incurred

Based on the completion objectives, well completion is divided into 3 basic styles.
These are

1- temporary

2- permanent

3- workover

The table below displays the difference between the different
styles of well completions

Well completion:' its significance in productivity'

     The significance of well completion lies in the fact that it is the
   only productivity factor, amongst three, which can be influenced by
         man to increase productivity.
         The two other productivity factors namely Reservoir Boundary
         & Reservoir properties are natural factors over which man
has no control.

Well completion & skin effect

        While designing well completion factor that must be taken into
   consideration is   the skin effect.
           Skin has a direct impact on well productivity which can
           be +ve or –ve. Skin is the change in radial flow geometry near
the well bore caused by flow
           convergance, wellbore damage, perforation, partial penetration and
          deviation. The effect of skin can be seen as a pressure drop across
          the completion this drop in pressure results from reduction in total
          pressure available to bring fluids from a distance R_e to the well
          bore at distance R_w.the pressure at distance R_e from the well
bore axis is the undisturbed reservoir pressure.P_ewhrer as the
          pressure at a distance R_wfrom the well bore axis is the well
bore pressure P_wf. the resultant pressure drop is the draw down
         that causes movement of fluids from a distance R_e to the distance R_w

There are different ways to maximize the productivity. These include:

1- creating highly conductive path to the well bore by fracturing the formation

2- reducing the viscosity by employing methods such as steam injection

3- removing skin by employing methods such as acidizing

4- increasing well penetration by perforating deeper into the formation

5- reducing formation volume factor by choosing correct surface separator

Types of well completion:

1- open hole completion

2- cased hole completion "in which we use perforation"

3- slotted linear completion

4- gravel back completion

Rig components part (3)

2012-03-02T09:03:00.001-08:00

Slips

Wedge-shaped pieces of metal with teeth or other gripping
elements that are used to prevent pipe from slipping down
into the hole or to hold pipe in place. Rotary slips fit
around the drill pipe and wedge against the master
bushing to support the pipe. Power slips are pneumatically
or hydraulically actuated devices that allow the crew to
dispense with the manual handling of slips when making a
connection. Packers and other down hole equipment are
secured in position by slips that engage the pipe by action
directed at the surface.

Spinning Chain

A relatively short length of chain attached to the tong pull
chain on the manual tongs used to make up drill pipe. The
spinning chain is attached to the pull chain so that a crew
member can wrap the spinning chain several times around
the tool joint box of a joint of drill pipe suspended in the
rotary table. After crew members stab the pin of another
tool joint into the box end, one of them then grasps the
end of the spinning chain and with a rapid upward motion
of the wrist "throws the spinning chain"—that is, causes it to unwrap from the box and coil upward onto the body of
the joint stabbed into the box. The driller then actuates
the makeup cathead to pull the chain off of the pipe body,
which causes the pipe to spin and thus the pin threads to
spin into the box.

Stairways

Stairs leading from one level to another. Protected with
handrails.

Standpipe

A vertical pipe rising along the side of the derrick or mast.
It joins the discharge line leading from the mud pump to
the rotary hose and through which mud is pumped going
into the hole.

Substructure

The foundation on which the derrick or mast and usually
the drawworks sit; contains space for storage and well
control equipment.

Surface Casing

Usually the first casing to be run in a well. This is done
after spudding-in so a blowout preventer can be installed
before drilling is started.

Swivel

A rotary tool that is hung from the rotary hook and
traveling block to suspend and permit free rotation of the
drill stem. It also provides a connection for the rotary hose
and a passageway for the flow of drilling fluid into the drill
stem.

Tongs

The large wrenches used for turning when making up or
breaking out drill pipe, casing, tubing, or other pipe;
variously called casing tongs, rotary tongs, and so forth
according to the specific use. Power tongs are pneumatically or hydraulically operated tools that spin the
pipe up and, in some instances, apply the final makeup
torque.

Top Drive

The top drive rotates the drill string end bit without the
use of a kelly and rotary table. The top drive is operated
from a control console on the rig floor.

Traveling Block

An arrangement of pulleys or sheaves through which
drilling cable is reeved, which moves up or down in the
derrick or mast.

Walkways

An area cleared for moving through by personnel and
protected with a handrail.

Water Tank

Is used to store water that is used for mud mixing,
cementing, and rig cleaning.

Weight Indicator

A device for measuring the weight of the drill string.
Monthly calibration to calculated drill string weight is
required by API.

Rig components part (2)

2012-03-02T09:00:00.001-08:00

Engine Generator Sets

A diesel, Liquefied Petroleum Gas (LPG), natural gas, or
gasoline engine, along with a mechanical transmission and
generator for producing power for the drilling rig. Newer
rigs use electric generators to power electric motors on
the other parts of the rig.
Fuel Tanks

Fuel storage tanks for the power generating system.

Hoisting Line

A wire rope used in hoisting operations. Must conform to
the API standards for its intended uses.

Hook

A large, hook-shaped device from which the elevator bails
or the swivel is suspended. It is designed to carry
maximum loads ranging from 100 to 650 tons and turns
on bearings in its supporting housing.

Kelly

The heavy square or hexagonal steel member suspended
from the swivel through the rotary table. It is connected to
the topmost joint of drill pipe to turn the drill stem as the
rotary table turns.

Kelly Bushing

A device fitted to the rotary table through which the kelly
passes. It is the means by which the torque of the rotary
table is transmitted to the kelly and to the drill stem. Als
called the drive bushing.

Kelly Spinner

A device for spinning the drill pipe. Replaces the spinning
chain.

Mast

A portable derrick capable of being erected as a unit, as
distinguished from a standard derrick, which cannot be
raised to a working position as a unit.

Monkeyboard

The derrickman's working platform. Double board, tribble
board, fourable board; a monkey board located at a height
in the derrick or mast equal to two, three, or four lengths
of pipe respectively.

Mousehole

Shallow bores under the rig floor, usually lined with pipe,
in which joints of drill pipe are temporarily suspended for
later connection to the drill string.
Mud-Gas Separator

A device that removes gas from the mud coming out of a
well when a kick is being circulated out.

Mud Pits

A series of open tanks, usually made of steel plates,
through which the drilling mud is cycled to allow sand and
sediments to settle out. Additives are mixed with the mud
in the pit, and the fluid is temporarily stored there before
being pumped back into the well. Mud pit compartments
are also called shaker pits, settling pits, and suction pits,
depending on their main purpose.

Mud Pump

A large reciprocating pump used to circulate the mud
(drilling fluid) on a drilling rig.

Mud Return Line

A trough or pipe, placed between the surface connections
at the well bore and the shale shaker. Drilling mud flows
through it upon its return to the surface from the hole

Pipe Racks

A horizontal support for tubular goods.

Pipe Ramp

An angled ramp for dragging drill pipe up to the drilling
platform or bringing pipe down off the drill platform.

A blowout preventer that uses rams to seal off pressure on
a hole that is with or without pipe. It is also called a ram
preventer. Ram-type preventers have interchangeable ram
blocks to accommodate different O.D. drill pipe, casing, or
tubing.

Rathole

A hole in the rig floor 30 to 35 feet deep, lined with casing
that projects above the floor. The kelly is placed in the
rathole when hoisting operations are in progress.

Reserve Pits

A mud pit in which a supply of drilling fluid has been
stored. Also, a waste pit, usually an excavated, earthen-
walled pit. It may be lined with plastic to prevent soil
contamination.

Rotary Hose

The hose on a rotary drilling rig that conducts the drilling
fluid from the mud pump and standpipe to the swivel and
kelly; also called the mud hose or the kelly hose.

Ram Blowout Preventer
Rotary Table

The principal component of a rotary, or rotary machine,
used to turn the drill stem and support the drilling
assembly. It has a beveled gear arrangement to create the
rotational motion and an opening into which bushings are
fitted to drive and support the drilling assembly.

Note the pipe spinner (in red) on the side of the swivel.

Shale Shaker

A series of trays with sieves or screens that vibrate to
remove cuttings from circulating fluid in rotary drilling
operations. The size of the openings in the sieve is
selected to match the size of the solids in the drilling fluid
and the anticipated size of cuttings. Also called a shaker.

Rig components part(1)

2012-03-02T08:01:00.000-08:00

Accumulator
The storage device for nitrogen pressurized
hydraulic fluid, which is used in operating the
blowout preventers.

Annular Blowout Preventer
A large valve, usually installed above the ram preventers,
that forms a seal in the annular space between the pipe
and well bore. If no pipe is present, it forms a seal on the
well bore itself.

Annulus
The space around a pipe in a well bore, the outer wall of
which may be the wall of either the bore hole or the
casing; sometimes termed the annular space.

Blowout Preventer

A large valve, usually installed above the ram preventers,
that forms a seal in the annular space between the pipe
and well bore or, if no pipe is present, on the well bore
itself.

Brake

The braking device on the drawworks to stop a load being
lifted.

Bulk Mud Components in Storage

Hopper type tanks for storage of drilling fluid components.

Casing Head

A heavy, flanged steel fitting connected to the first string
of casing. It provides a housing for slips and packing
assemblies, allows suspension of intermediate and
production strings of casing, and supplies the means for
the annulus to be sealed off. Also called a spool.

Cathead

A spool-shaped attachment on a winch around which rope
for hoisting and pulling is wound.

Catline Boom and Hoist Line

A structural framework erected near the top of the derrick
for lifting material.

Catwalk

The ramp at the side of the drilling rig where pipe is laid to
be lifted to the derrick floor by the catline or by an air
hoist.

Cellar

A pit in the ground to provide additional height between
the rig floor and the well head to accommodate the
installation of blowout preventers, ratholes, mouseholes,
and so forth. It also collects drainage water and other
fluids for disposal.

Choke Manifold

The arrangement of piping and special valves, called
chokes, through which drilling mud is circulated when the
blowout preventers are closed to control the pressures
encountered during a kick.

Conductor Pipe

The largest diameter casing and the topmost length of
casing. It is relatively short and encases the topmost
string of casing.

Crown Block and Water Table

An assembly of sheaves or pulleys mounted on beams at
the top of the derrick. The drilling line is run over the
sheaves down to the hoisting drum.
Degasser

The equipment used to remove unwanted gas from a
liquid, especially from drilling fluid.

Desander

A centrifugal device for removing sand from drilling fluid to
prevent abrasion of the pumps. It may be operated
mechanically or by a fast -moving stream of fluid inside a
special cone-shaped vessel, in which case it is sometimes
called a hydrocyclone.

Desilter

A centrifugal device, similar to a desander, used to remove
very fine particles, or silt, from drilling fluid. This keeps
the amount of solids in the fluid to the lowest possible
level.

Doghouse

A small enclosure on the rig floor used as an office for the
driller or as a storehouse for small objects. Also, any small
building used as an office or for storage.

Drawworks

The hoisting mechanism on a drilling rig. It is essentially a
large winch that spools off or takes in the drilling line and
thus raises or lowers the drill stem and bit.

Drill Bit

The cutting or boring element used in drilling oil and gas
wells. Most bits used in rotary drilling are roller-cone bits.
The bit consists of the cutting elements and the circulating
element. The circulating element permits the passage of
drilling fluid and uses the hydraulic force of the fluid
stream to improve drilling rates.

Drill Collar

A heavy, thick-walled tube, usually steel, used between
the drill pipe and the bit in the drill stem. It is used to put
weight on the bit so that the bit can drill.

Drill Pipe

The heavy seamless tubing used to rotate the bit and
circulate the drilling fluid. Joints of pipe 30 feet long are
coupled together with tool joints.

Driller's Console

The control panel, located on the platform, where the
driller controls drilling operations.

Drilling Line

A wire rope hoisting line, reeved on sheaves of the crown
block and traveling block (in effect a block and tackle). Its
primary purpose is to hoist or lower drill pipe or casing
from or into a well. Also, a wire rope used to support the
drilling tools.

Electric Control House

On diesel electric rigs, powerful diesel engines drive large
electric generators. The generators produce electricity that
flows through cables to electric switches and control
equipment enclosed in a control cabinet or panel.
Electricity is fed to electric motors via the panel.

Electric Cable Tray

Supports the heavy electrical cables that feed the power
from the control panel to the rig motors.

Elevators

A set of clamps that grips a stand, or column, of casing,
tubing, drill pipe, or sucker rods, so the stand can be
raised or lowered into the hole.

Xmas Trees

2012-03-02T07:31:00.000-08:00

Xmas Trees

Primary flow control system for well once in production

Features and access requirements

•Outflow from well - production

•Inflow to well - injection or killing

•Vertical access to tubing - wire line, coiled tubing

Xmas Tree Components

•Pressure gauges (accessory)

– safety hazard / potential wrong pressure readings

•Gauge flange or tree cap

–provides seal for top of tree

•Lubricator valve

–isolate pressure, well access for intervention tools

•Flow tee

–used to direct flow, enable thru-tubing access

•Production wing valve

–used to isolate well for most routine operations

•Kill wing valve

–enables connection of pumping equipment

•Choke (accessory)

–controls rate of flow from well

•Master valves (main isolation valves)

–Upper Master Valve (operational valve), optional: hydraulic / pneumatic controlled
Surface Safety Valve

–Lower Master Valve (back-up valve)

manually operated

Categories of Xmas Tree

Flanged tree

•Several flanged components

– each connection is a potential leak path

•Much more common than monoblock design

•More flexible than monoblock design

•takes up more space (height)

Monoblock construction tree

•Single block construction

•Fewer possible leak paths

•Used in high pressure/leak sensitive locations

Monoblock Xmas Tree

Comprises inline or "Y" shaped block of single casting/forging

Valving arrangement

•Lower Master Valve (manual)

•Upper Master Valve (Surface Safety Valve)

•Y piece or side outlet flanges

–houses both production and kill wing valves

•Uppermost valve (manual swab valve)

Multiple Completions

Cases where more than one completion string installed

•Each string independently suspended

•Must seal off tubing casing annulus

–either independently or collectively

•Independent control of fluid flow in each string

Xmas Tree Selection

produce a listing of the parameters of the anticipated process or operating envelope

- Classify the Well Type

Water Well ( low or medium pressure, Rate )

Oil Well (low, medium or high pressure, GOR, Rate )

Gas Well ( low, medium or high pressure, WGR, Rate)

This will be the basis for the design and the selection of equipment type and rating

wellhead installation