drilling 1

Notes

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Basic Petroleum EngineeringSchlumberger

Drilling

DrillingObjectivesExploration

Well TypesDrilling process

Life of a well Perforation

Production problems

© JJ Consulting 1997

Notes

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Hydrocarbon in PlaceThe Objective of most wells is to find hydrocarbons. The volume of hydrocarbons in place is given by:

H=Constant x φ(1−Sw)hΑ

where

H = initial oil in place

φ = effective porosity

Sw= initial water saturation

h = productive interval

A = drainage area

This is the formula giving the amount of oil in place, vital for the exploitation of the reservoir.

Logs give

porosity

saturation

height (from the depth)

This means they are vital to the operator.

Area comes from surface seismic and/or well testing

Notes

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Hydrocarbon in Place - 2

This is simple to visualise

A - area of the reservoir

h - the thickness of the reservoirtogether the product gives the total volume of rock

φ - percentage of pore space in that volume of rock. i.e. the volume that contains fluids

Sw = percentage of the pore space containing water so(1-Sw) = percentage of pore space containing hydrocarbons

Hence the equations for the hydrocarbons in place

The constant in the equation is used to put the result into the required units, for example in oilfield units it is acre-ft.

Logging measurements form a major part of the input to this equation, hence their importance. Errors in reading or interpreting the logs is reflected in the results of the hydrocarbon in place.

Notes

The seismic source was originally dynamite; this has largely been replaced by air and water implosion guns and VibroSeis trucks on land. The latter drop a heavy weight to create the noise.

The modern 3D survey has lines spaced about 25 - 50m apart with the geophones spaced every 25m or so giving a detailed picture of the subsurface.

The processing of the data is quite simple but takes a considerable time due to the high volume of data.

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Exploration - Seismic

Surface seismic consists of making a “noise” and listening for the returning reflected signals.

There are two types of survey2D - with widely spaced lines of geophones

3D - with closely spaced linesThe raw seismic data is processed to give a time picture of the subsurface.

Notes

This picture shows a seismic section clearly showing the bedding planes. The interpreted cross section shows how the geophysicist puts the various rock types into the picture. At this time he will also make a time to depth conversion. Surface seismic is always recorded as two-way-time, which is useless for drilling. This time is converted into a depth. On this example is also shown the logs that assist the conversion.

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Seismic example

A surface seismic with the interpreted model above.

Notes

The seismic only gives the structure of the formations, there is no information on the rock types. The geologist goes to an outcrop which may be tens of kilometers away and tries to match up the rocks there with the sub-surface picture seen on the seismic.

The job of the geochemist is more difficult as he must identify, not only the source rock but also show a potential migration path. This is a difficult task even in a known basin.

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Exploration - Geology

In addition to seismic there are other techniques that must be applied to evaluate an exploration prospect.

Geology

The geologist goes to outcrops (where the formations are exposed on surface) and identifies potential cap and reservoir rocks.

Geochemistry

The geochemist tries to identify the source rock and also the possible migration path to the reservoir rock.

Notes

The driller has to have a lot of data before he can design the drilling plan. He needs to have the rock type to chose his bits, estimate his drilling speed, and identify potential problems such as swelling shales. He needs to have the pressures to ensure his mud weight is correct to balance the reservoir.

The resulting plan will be a time - depth plot showing the expected time for drilling each section, the depth of the expected casing points and any additional time for other operations. There will also be detailed specifications on casing, etc to be used.

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Drilling Objectives

The objective of a well is to reach a reservoir zone safely and efficiently and then produce the fluids.

Step 1

identify the reservoir and the beds above it which have to be drilled.

Step 2identify the reservoir fluids and pressures

expected; in addition the fluids and pressures of the zones above also have to be estimated.

Step 3plan a series of casing points to minimise

the risks.

Notes

This is a typical geological section that the driller would have to work with. It shows all the expected formations. The additional information needed is the depth of each and the pressures and fluids in each zone.

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Well Prognosis

This is the geology of the proposed well.

The drilling engineers job is to plan a well to arrive at the target reservoirs safely and efficiently.

Conglomerate

Shale withsandstonelayers(?)

Salt withCarbonateStringers

Cap Rock

Reservoir 1

Reservoir 2

Notes

The first casing is set across the conglomerate and the shale/sandstone. The potential of caving in the surface layer is high but should pose few problems. Shallow gas can be a considerable problem in some areas. Not only is there the possibility of a blow out but gas is difficult to cement properly. This could mean that there will be gas leaking between the casings.

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Drilling Plan

The surface hole is drilled to the top of the salt zone.

Potential problems in the top zone here include

- caving in unconsolidated conglomerate formations.

- shallow gas in the sandstone layers.

Conglomerate



Cap Rock

Reservoir 1

Reservoir 2

Notes

The final well finished in two more stages. The first through the very difficult salt formation. Here is the problem of which mud to use, salt saturated or oil base, to avoid the salt dissolving. Then there is the problem of possible overpressured stringers, where heavy mud will be required to control them.

The reservoir zones should give few problems. Some operators insist on an intermediate stop if there are two reservoirs such as found here. This allows them to evaluate one reservoir at least in case they lose the well.

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Final Well

The next stages are to drill the well to the cap rock and then set casing before drilling the reservoir.Potential problems here are- salt dissolving in the drilling mud, need to use oil base mud or salt saturated mud.- high pressure in the carbonate stringers

- a gas gap and hence high pressure in the reservoir zones.

Conglomerate



Cap Rock

Reservoir 1

Reservoir 2

Notes

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Vertical Wells

Wells can be split into three categories

1) Vertical

• drilled to a specific target

• measured depth = true depth

Vertical wells are most common in exploration situations. The well is drilled to its target without the complications of deviation.

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Deviated well

2) Deviated

• usually from a platform or

• from land to near offshore

• measured depth has to be converted to true vertical depth

possible well tracks

Target formation

Deviated wells are very common in a lot of situations. The well track can be almost anything; starting vertical and then deviating, starting vertical, deviating and then vertical again, starting deviated and then going vertical. The change in direction is called a dog-leg. Severe doglegs can cause problems for logging as it makes it difficult for the tool to go down and sometimes to come out. The deviation angle is measured with respect to the vertical. The true depth has to be computed, knowing this angle and how it has changed.

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Horizontal well

3) Horizontal

• drilled to maximise production or minimise problems such as coning

• well is precisely guided along a predetermined track

Vertical section

Curvature

Ramp

The ultimate deviated well is a horizontal well. Here the well is drilled in three sections, the vertical section, the curved section and finally the ramp. The curved section is typically a couple of hundred metres but can be less for specific cases. The ramp is as long as required, several kilometres is common. Guiding the well is done from surface using sensors mounted near the drill bit. These give information on direction and deviation as well as logging data such as gamma ray which helps in guiding the well paths.

Notes

The depth is different depending on whether the wells are vertical or horizontal. In addition there are differences if the drilling is on land or offshore. However the reservoir is at a constant depth irrespective of the surface topography. Hence a reference is used to give a precise repeatable depth. The reference is mean sea level.

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Depth Overview

The depths and position of all wells has to be well known. This is important in mapping and evaluation.

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Rig Personnel

Company representative

Toolpusher

Driller

Asst Driller

Derrick man

Roughneck

Maintenance

The Company Representative (company man) is the Operating companys man on site. He directs the operations on the rig. Service Company personnel report to him.The Tool Pusher is employed by the drilling company. He oversees all operations onthe rig, primarily the drilling but also service company activities.The Driller and the drilling crew actually drill the well under the control of the toolpusher. He drills from the drillers console on the rig floor. The rest of the crew areAssistant driller - the number 2 on the rig floorDerrick man - works on the mast during trips handling the stacking of the drill stringsRoughneck - general helper both on the rig floor and elsewhere on the rig site.

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Rig Hoist

crown block

mast

drill floordraw works

drilling line

travelling block

hook

links

elevator

crown block

The rigs hoisting system consists of two parts; the mast itself which is the supporting structure for the lifting system and the lifting system itself. The latter consists of

Crown Block - a set of sheaves fixed at the top of the mast

Travelling block - a set of sheaves at the other end of the loop of the drilling line with a hook at the bottom

Elevators - heavy duty clamps attached to the hook on the travelling block. During drilling the hang to the side of the swivel. they are used during tripping to lift the drill pipe and collars

Drilling line - heavy steel wire

Draw works - located on the rig floor near the rotary table, provide the winch system

Notes

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Swivel

gooseneck

drilling fluid in

fixed

free

to drill string

bearing

The Swivel permits the Kelly and hence the drill string to rotate freely during drilling operations. It is attached to the travelling block via the hook. It also allows the passage of the drilling fluids down the drill string. It is a large bearing.

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Rig Floor

Drillers console

dog house

draw works

V-door ramp

drive

mouse hole

rat hole

The rig floor contains most of the major rig components. The draw works provide the lifting power.

The rotary drive gives torque to the drill string.

The mouse hole is the storage for the next bit of drill pipe to be added to the string.

The rat hole is a temporary store for the kelly while the drill pipe is being attached.

The console is the centre for the entire operation. The driller has all the necessary controls to manage the drilling plus readouts to give him measurements of the weight on the bit, torque and so on.

The V-door and the associated ramp are the access points for any items to be brought on to the rig floor.

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Rotary system

The rotary system has a number of major components

The Rotary Table provides the rotational power to the system. It transmits this via the master bushing and the kelly bushing to the drill string. The Kelly bushing has the same cross section as the kelly hence the kelly rotates.

These components are removable.

Notes

The top drive system uses a dc electric motor to drive the drill string instead of the rotary table. The motor is attached to the standard swivel above it and to the drill string below. There is no need for a special kelly. This means that one stand of drill pipe can be drilled at one time, saving on the connection time and hence rig time.

This system is used on about 70% of offshore and 30% of land rigs.

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Top Drive System

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Rotary table

The Master bushing is also used to suspend the drill string during running in or pulling out of the hole. In this case the drill string is held by the slips. These are a set of tapered grips.

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BOP stack

The BOP stack is the main safety system on the rig. It consists of several devices. The first are pipe rams, designed to fit snugly around the drill pipes and prevent any fluid passing up the annulus. The annular preventer is a rubber device which, within reason, can fit any shape, e.g. the kelly. The blind rams will seal if there is no drill pipe in the hole simply closing the hole. Shear rams will cut through anything in the borehole sealing it off entirely.

Also in the stack is a kill line to be able to pump mud into the well at any stage to kill it. The choke line is used to regulate pressure on the annulus.

BOP stacks are hydraulically operated.

Notes

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Tubulars

There are three basic types of tubulars used in the drilling phase of a well. The Kelly is a square (or other flat sided shape) pipe used in the rotation system to transmit torque.

Drill collars are used down near the bit to provide weight to the drill string. They are very thick walled.

Drill pipes form the major part of a drill string.

All the tubulars are hollow to allow transmission of the drilling fluids. The dimensions are given by the outer diameter and the weight. The weight (in pounds per foot) determines the inner diameter. The normal length of a drill pipe or drill collar is 30 feet (10m). In normal operations the dp is made up into stands of three. This also occurs with dcs.

There are some specialised items such as stabilisers in the bottom hole assembly.

Notes

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Drilling Fluids

The drilling fluid is an essential part of the drilling and well control system

It can be either water or oil based

Oil based is an emulsion of diesel and water

water based uses anything from salt saturated to fresh water

Additives to the mud give it weight. the basic additive is bentonite. Barite is added for very heavy muds

Mud is used to

•Cool the bit

•Remove cuttings

•Lubricate the bit

•Provides a pressure to overcome that of the formation

•Makes a mud cake to seal permeable formations

The mud is circulated down the drill string and and back up the annulus. When it reaches surface it is first passed over the shale shakers to remove the cuttings debris. It may then be passed through a degasser, desiltter, desander or mud-gas separator to recondition it before it is returned to the mud pits for reuse.

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Mud weights

The mud density is kept at a level to overcome expected reservoir pressures and keep the well at a positive “overpressure”.

It should not be too heavy or it will crack the formation.

Mud weights are quoted in g/cc, lb/ft or lb/gal. This is essentially a density.

If the formation pressure is known the mud weight for equilibrium can be computed.

Example

The reservoir pressure is 5400 psi. The depth is 10000’.

The gradient is 0.54 psi/ft.

This is equivalent to 1.25 g/cc or 78 lb/cu ft or 10.4 lb/gal

The mud weight is an important parameter in drilling. New mud is made for each section of the well as the pressures and formations are different.

Notes

Conversion factors:

0.433psi/ft = 1g/cc

1 psi/ft = 19.27lb/gal

1 psi/ft = 144 lb/cu ft

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Mud Weight ExampleCompute the mud weight need to drill into the gas at the top of the reservoir.

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Casing

Casing sizes depend on the purpose . They start large and gradually become smaller

Casing sizes are always given as Outer Diameter.

The Inner Diameter depends on the weight

The drift is the maximum difference with the nominal value of the id.

In addition to these a surface casing, the conductor pipe is usually set. This has a normal diameter of 30”.

Notes

The process of cementing is a simple one, a cleaning fluid is first pumped up behind the casing to break up the mud and mud-cake ensuring a good bond to the formation. The cement is then pumped, and a completion fluid is left in the wellbore.

An essential requirement for a good cement job is centralised casing. The numbers of centralisers needed is predicted using a computer program with inputs such as well depth and deviation.

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Cementing

Cementing is used to fix the casing in place and provide mechanical strength to the system.

The most essential use of cementing is to seal one zone from another.The cementing of a casing is performed by pumping cement slurry down the casing and forcing it up between the casing and the formation.

Great care is taken to ensure a complete coverage of the cement.If the cement is found to be poor, a squeeze has to be made to repair the deficit.

The cement is usually left to set for a couple of days before drilling ahead.

Notes

The major initial use of logging is to tell the oil company where the hydrocarbon is and how much is there. In addition to this service logs provide a lot of data that could not be easily obtained by any other method.

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Logging

Logging is a process of obtaining information about the formation after the well has been drilled.

A sensor is lowered into the well on the end of an electrical cable. This provides power and transmits the data to the surface where it is presented in the form of a “graph” against depth.

There are many types of logs;

resistivity logs show where the hydrocarbon may be, high resistivity means hydrocarbonporosity logs show porous reservoir zones

sonic and density logs give information about the rock types.

Notes

There are many log services that are used in testing. One important one is depth measurement. This is made at the initial logging of the well and is then used as the depth reference for the rest of that wells life.

Cement Bond Logs, Corrosion logs and Production Logs give detailed information on the well which helps explain test results.

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Testing and Logging

Some logs that are useful in Testing operations.

Gamma Ray - shows shale and clean zones, gives net and gross pay.

Cement bond logs - show how good the cement is and if there may be channels and problems.Corrosion logs - show possible problems inside and outside the casing.Production logs - show flow in the well.

CCL - shows the casing collars

Notes

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Life of a well-1

Drilled well Cased Well Perforated Well

Need to find:

Saturation casing integrity

Porosity cement quality

Zones

The information requirements in a wells life depend on the stage. The first stage of the well is short, a few months. Once the well is drilled the question is “where is the hydrocarbon?” The logs are run for this purpose. Once the well is cased and cemented, the question is “how good is the cement”. Then the zone(s) are perforated.

Once cased it is difficult to make measurements, especially of the important resistivity.

Notes

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Life of a well-2

Well Produced Workover activity Recompleted

Need to know:

Production Perforation efficiency Flow rates

fluid mix new zones Zone Production

Pressures Flow rates Pressures

In the second “half” of a wells life the questions are different. Here the emphasis is on production , fluids and pressures. Different techniques are employed. Well testing and reservoir monitoring tools are used to answer most of the questions. Some specialist devices such as corrosion monitoring tools may be required. The phase of the wells life lasts for a much longer time, often years; hence there will be a number of surveys during this time.

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Completing a well

When a well is drilled it needs to be completed

The objective of a completion is to produce the well’s fluids safely and efficiently

Completions can take a lot of different forms

•single string tubing

•dual string tubing

•annulus

there is also a choice in how the reservoir zone is handled:

•perforated casing

•open hole

•gravel pack

The choice of the correct type of completion is vital to the future of the well

The choice of a completion is a essential part of the well construction. Numerous computer programs help the engineer decide on the type he will employ.

For example the choice between single and dual tubing depends on the zones to be completed their individual pressures, the reservoir performance in each zone. If a dual is selected this means a smaller tubing in the same casing or a larger hole and the same tubing's. In either case there is an expense involved.

Notes

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Tubing Completions

The most common type of completion. The fluid is directed to surface in a tubing set in a packer. There can be a lot of zones using either one single tubing or flowing through a tubing per zone. (the normal maximum is two tubings in a well).

Tubing completion is made up of a tubing set in a fixed packer, the annulus is sealed.

The tubing itself has a number of nipples and seats at the bottom to accommodate valves and so on.

Notes

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Tubing completions

This common type of completion has several advantages over the others:

•Flow is sent up a narrow tubing, hence easily controlled

•the tubing can be removed or replaced easily during workover

•the well is easily controlled

•zones can be selectively produced without mixing

The disadvantage is that there is extra material in the well thus extra cost.

The tubing is by far the most common type as it is easy to control the behaviour of the well. It is also relatively simple to change with a workover.

Notes

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Annulus Completion

A variation on the tubing completion. Fluid is allowed to flow up both the tubing and the annulus

This type of completion is used for wells at the opposite end of the flow rate spectrum.

In ultra high flow rate wells the well is allowed to flow up through the annulus itself, there is no flow up the tubing. This is done as a tubing would be too small to accommodate the flow rate of the well.. The tubing here is for well control, is the well needs a workover it can be killed.

At the opposite end wells which will not produce to surface have to be pumped. A pump is placed in the tubing and the well flowed through the tubing.

Notes

This pumped completion shows the well flowing up to a level in the annulus but not to surface. The pump pulls the fluid up the tubing. This can either be, as shown, a sucker rod pump (nodding donkey) or a submersible pump run by electricity from surface.

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Pumped Completion

Notes

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Open Hole Completion

The simplest form of completing a reservoir zone is the open hole completion. The casing is set in the overlying cap rock. The reservoir is penetrated for a few metres

This sort of completion works in very consolidated formations. It is flowed up through a tubing as with a standard completion.

Notes

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Open Hole CompletionsAdvantages

•Full bore diameter for flow

•no perforating is needed, cost saving

•can be easily recompleted or deepened later

•formation damage in the reservoir is minimised

Disadvantages

•no control of fluid entry

•no selective treatment of the formation is possible

•well is difficult to kill

•rock may collapse

This type of completion is usually employed in high flowrate wells and consolidated formations

Flowing a well from the maximum possible area gives a very good performance with little or no damage. However the problem with an open hole completion is formation collapse, only the very consolidated rocks, carbonates, will stand such a system.

Notes

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Gravel Pack Completion

The gravel pack completion is used where there is a need to control sand production. It retains the high flow area of the open hole completion The major elements are a wire screen and the gravel pumped behind it.

The placing of a gravel pack can be difficult, there are a number of methods. The gravel is put in first and the screen lowered on drill pipe and forced into the gravel or the screen fixed first and the gravel placed in a similar manner to the cement.

Notes

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Gravel Pack Completions

Gravel packs are commonly used in unconsolidated sands.

Advantages are:

•keeps sand production down

•provides a large flow area

Disadvantages are:

•Expensive and complex to install

•difficult to perform any workover operation

•can introduce a skin effect in the reservoir

Gravel packs are common, retaining the advantages of the large flow area of the open hole completion while containing the formation collapse.

The disadvantages are that in placing the gravel pack the reservoir may be damaged.

Notes

This is a complex completion with three sand formations, each with a gravel pack. The three intervals can be flowed simultaneously by opening the sliding side doors (SSD) or each can be flowed separately by closing the unwanted zones. The expense of such a system is offset by its expected long lifetime allowing the separate layers to produce without interference.

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Gravel Pack Example

Notes

A gas lift completion is a very common device to assist the reservoir production. A typical reservoir will produce to surface for a number of years; as time goes on the reservoir pressure declines and the reservoir is no longer able to push the oil all the way to surface.

The solution is to lighten the oil column in the tubing. This is achieved by injecting gas into the tubing via valves from the annulus. This gas is usually produced gas making this a very efficient system.

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Gas Lift Completion

Notes

Perforation in casing is by far the most common method. This is done in both a normal completion and a gravel pack although the requirements are different. The gravel pack needs a lots of shots and an entry hole as big as possible. The standard completion needs deep penetration. Both are possible using varied charges

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Perforated reservoir

The commonest method of handling the reservoir zone.

A casing is set across the entire reservoir.

The zone to be produced can then be selectively perforated.

Advantages

- The reservoir is produced in only the best intervals

- Stimulation and repair are simple

- unwanted fluids are excluded

- production logging/monitoring of the reservoir performance is easily performed

Disadvantages

- the area for flow is small

- the perforations may not all produce

Notes

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Explosives

Explosive Categories

An Explosion

Sudden release of chemical, mechanical or atomic energy - Expanding gas, High Pressure

Chemical Explosives

Two main types:

1. Low Explosives or deflagrating.

2. High Explosives or detonating

Explosives are used in perforating and other well operations such as sample taking.

Notes

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Low Explosives Low Explosives

- Initiated by heat or flame.

- Pressure reaches 50 Kpsi.

- Used in CST guns.

Black Powder

- 75% Saltpetre KNO3 + 10% Sulfur + 15% Charcoal.

- Fine, black powder.

-- Uses: primer "needle" igniters (cst) & squibs

Western Ball

- Nitrocellulose

- Small black ball.

- Very hydroscopic (takes water from its surrounding).

- Uses: sealed plastic cst cartridges.

Others

- 83% Ammonium perchlorate (Cl NH4) + 17% Carbazol. White powder, looks like flour. Less powerful than Western Ball Powder. Flash point 550 degF. Rated at 450 degF for 1 hour.

- Uses: brass cst cartridges high temp.

- 86% Ammonium Perchlorate + 14% Carbozol. White powder. Flash point 550 degF. Rated at 450 degF for 1 hour.

- Uses: aluminium cst cartridges high temp.french high temp. (lb-51) .american high temp.

Notes

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High Explosives

High Explosives

Detonate rather than burn.

- Pressure reaches 50 K to 4Mpsi.

Two categories:

1. Primary High Explosive

- Initiated by hot wire / flame.

- Burn first, then undergo transition from deflagrating to detonating

- Sensitive to shock / friction.

- Use in blasting caps.

2. Secondary High Explosive

- High energy shock wave will initiate the detonation.

- Can explode if heated in confinement.

- Use in primacords and shaped charges.

Primary - Lead Azide Sulfone- Pb N6 - Very sensitive to friction. Will self detonate when heated sufficiently at atmospheric pressure. Flash point 625 degF. Uses: Blasting Caps, Boosters.

Secondary - RDX - White crystalline solid (dyed pink) with a melting point of 388 degF , crystal density 1.82 gr/cc, with detona tion velocity of 8,400 m/sec. RDX "outgasses" or decomposes harmlessly when heated or burned at atmospheric pressure, however, will detonate if heated in confinement above 180 degC Rated at 340 degF for 1 hour, when not exposed to well pressure or 320 degF when exposed. This rating corresponds to an average rate of descent of 20,000 ft/hr without appreciable lowering of charge performance. Insoluble in water and alcohol.

- Uses: Detonating Cord, & Shaped Charges of All Types SN6 O14 (Picryl-Sulfone) Yellow powder. Flash point 584 degF. Rated at 470 degF for 1 hour.

- Uses: Shaped Charges & Detonating Cord High Temp.Secondary High Explosives

Notes

Perforation is the most popular method of reservoir completion. The objective is to create a path for flow from the formation to the well through the casing and cement. The requirement is thus for a hole to be made in the casing, cement and into the formation for a short distance. Standard perforations have an entrance hole of about 0.4” and a penetration of around 20”.

The perforation “gun” contains these three components. The detonator to start the reaction, the prime cord to propagate it and the shaped charge to make the holes.

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Perforation

Gun systems use three components:

- detonator - primary high explosive ignited by heat or shock

- primacord - secondary high explosive ignited by the detonator, burns at 8400 m/sec

- shaped charges - create the perforations, detonated by the primacord.

Notes

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Shaped charge

The dimensions of the perforation, length of the tunnel, and diameter of the entrance hole are linked and depend on the geometry of the shaped charge.

A wide mouth gives a large entry hole and shallow penetration.

A narrow mouth gives deep penetration but a smaller hole.

Shaped Charges were developed shortly after World War II from the military bazooka weapon.

Three basic elements of a shaped charge

1. Case (Steel or Aluminium).

2. Cylinder of High Explosive & a Primer.

3. Conical Metallic Liner.

It was found that the conical shape produced a depression / hole in a metal target. The addition of the liner increased the efficiency of the system. Modern liners are made of powdered metal and leave a powder residue at the end of the perforation. A Typical charge has only about 20 grams of explosive material.

The pressure causes the material in the path of the jet of metal to move out of the way creating the perforation.

If the liner opening is widened the entrance hole size increases but the penetration decreases. These type of charges are used for applications such as gravel pack.

Notes

The liner is forced inside out to create the liner. The liner tip is at several million psi hence the penetration. The depth of penetration is at maximum about 35 inches as the objective of perforation is to create a pathway for flow between the formation and the wellbore. The liner is made of powdered metal which ends up as dust which is washed away by the flow.

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Jet Formation

The explosion starts at the base of the liner.

The detonation front forces the liner to flow forming a characteristic jet shape.

The jet tip is moving at high speed but the main reason for the penetration is the pressure.

Detonator Cord

Case Liner Primer Charge

Explosive

Detonation Front

Tips (7000m/s)

Tail (500m/s)

Jet Tip

(15 x 106 psi)

Tail Particles

Notes

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A Perforation

A picture of a glass being perforated.It happens so quickly that the glass remains intact after the jet has passed through.It will shatter a very short time later when the shock wave arrives.

Notes

The advantage of a casing gun completion is that all perforation material is carried inside the carrier hence it is protected from the well fluids. The resulting debris is also brought out of the well in the same carrier. The carrier can be either re-usable or not depending on the type of operation being performed. The more complex gun types are all “ throw-away” type carriers. The disadvantage of overbalanced perforation is that the mud in the well bore will enter the well as it is at a higher pressure. Through tubing perforation eliminates the invasion problem and gives the formation the chance to flow immediately. The disadvantage is that smaller guns have to be used, which means either smaller charges in a small carrier, or larger charges exposed to well fluids and debris left in the well. The choice depends on the type of well being perforated.

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FTC

52


Types of Perforation

Three Types of perforated completion

a) Wireline - Carried on an electric line

1) Casing Gun Completion

Well Pressure > Formation Pressure

Overbalanced perforating

Large diameter carrier gun

2) Through Tubing Perforation

Well Pressure < Formation Pressure.

Completion and final surface production equipment, or a temporary completion and testing facilities are in place

Underbalanced perforating, with pressure control equipment

Through tubing gun (small guns)

Gauges can be run with the string

Notes

Tubing conveyed perforation ( TCP ) connects a carrier gun to the end of the drill pipe or tubing. The gun can be fired by a number different types of detonators such as drop bar, pressure firing heads or inductive coupling. The choice depends on the conditions and type of well.

The advantages of this method are mainly the long interval (s) possible and the possibility of a simultaneous well test using downhole gauges.

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FTC

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Tubing Conveyed Perforating

b)Carried on Drill Pipe or Tubing

3) Tubing Conveyed Perforating

Perforation gun is carried on either the drill pipe or on tubing.

Well Pressure < or > Formation Pressure

Large interval of perforation in one run - in - hole

High explosive content, perforation spacing

Gauges can be run at the same time

Notes

The number of shots per foot depends on the application and the reservoir parameters. The objective is to obtain the best flow efficiency most economically. Computer program exists which allow the reservoir engineer to select the best combination of shots per foot and phasing. The most common number of shots per foot is four or six.

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FTC

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Perforation Characteristics

Guns are classified by the number of shots per foot, spf.

The current maximum is 21 spf.

Guns are also described by their Phasing- the directions of the perforations. This ranges from 0 degrees to 30/60 degrees

The example shows

90 degrees.

Notes

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FTC

55


Carrier Guns

These guns consist of pressure tight tubular steel carrier into which explosive shaped charges are mounted.

They are:

Casing Guns

- 3 3/8" , 4" and 5" O.D. Guns.

- for overbalanced perforating.

- reusable carrier

Scallop Guns

- small size.

- for underbalanced through-tubing perforating.

- disposable carrier.

High Shot Density (Hsd) Guns

- Large size

- HSD Guns can be run with Wireline or TCP.

-- disposable carrier.

Carrier guns have in common, an outer casing into which is put an expendable tube loaded with the charges.

They vary from the reusable casing guns to hsd carriers and the through tubing scallop guns.

Notes

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FTC

56


Casing Guns

Casing Guns

Features

- Retrievable gun.

- 4 shots per foot , 90 deg. phasing (22.5 deg. for squeeze guns).

- Common lengths: 10ft and 15ft per gun.

- Re-usable guns (15 to 20 times), mechanically rugged.

- Limited to 45ft in one run-in-hole.

- Mainly for overbalanced through casing perforating .

Notes

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Casing Guns 2

Advantages

- High reliability ,charges protected.

- High temperature (up to 400F)

- High pressure rating (25 000 psi).

- Gas tight.

- Resistant to chemicals.

- Selective firing system.

- No debris left in well.

- Little casing damage.

- Re-usable carrier.

- Large charge gives deep penetration.

Disadvantages

- Perforating holes not surged

- Drilling mud invades formation

- Limited length up to 45ft.

Notes

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FTC

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HSD

High Shot Density Guns

Features

- Retrievable gun with wireline operation.

- Retrievable or non-retrievable with TCP.

- Up to 21 shots per foot.

- 60, 120, 135/45, and 140/20 deg. phasing between shots.

- Common lengths: 5 ft , 10 ft and 20 ft.

- High explosive density and very good phasing.

- Big range of sizes ( 2 7/8" to 7 O.D.).

Notes

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FTC

59


HSD GunsAdvantages

- High reliability, charges protected.

- High temp & pressure rating.

- Gas tight.

- Resistant to chemicals.

- 21 shots per foot (high density)

- Large charge gives deep penetration.

- No debris left in well.

- Selectivity for small gun sizes.

Disadvantages

- Carrier not reusable.

- Very heavy guns.

- Big guns with maximum 20 ft in one run - in - hole.

- Overbalanced perforating has holes not surged clean and drilling mud invades formation

Notes

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FTC

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Through Tubing Guns

Enerjet Guns

Features

-Semi-expendable for 0 deg. phasing (strips are retrievable, but not reusable).

-Expendable for ± 45 deg. phasing (strips are not retrieved).

- 6 shots per foot , 0 or 180 degree phasing between shots.

- Shaped charges are attached to steel or aluminium carrier strip.

- Shaped charges are exposed to well condition.

- Mainly for underbalanced through tubing perforating

Notes

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FTC

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Enerjet Guns

Advantages

- Excellent charge performance for its size.

- Stiff , but flexible.

- 40 to 50 ft in one run-in-hole

-Temperature limitation.

- Easy assembly.

- Deeper penetration than scallop.

- Perforating holes surge clean.

Disadvantages

- Can only fire 2 guns selectively in one run-in-hole.

- Non H2S resistance.

- A lot of debris left in well after perforation.

Notes

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FTC

62


TCP

Tubing Conveyed Perforating

Features

- HSD Guns used.

- Run with Drill Pipe or Tubing (Permanent or Temporary).

- Normally underbalanced perforating, but long interval may be with overbalanced.

- Very long gun string is possible.

- Gun string is retrievable ( but can also be dropped in the well ).

Notes

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FTC

63


TCP 2Advantages

- Same as HSD.

- Top down firing.

- Very long gun string is possible

- Very safe underbalanced perforating.

- Overbalanced is also possible.

- Different types of firing methods.

- Pressure gauges to monitor well pressure.

Disadvantages

- Needs correlation of string with GR + pip tags.

- Much hardware required.

- Unreliable indication of whole string firing.

- A misfire will have a long lost time.

- Temp. rating of explosive needs to be high (long exposure).

Notes

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FTC

64


Channelling

Unwanted fluids are produced because of channels in the cement.

The only solution is to pull the completion and squeeze.

A typical problem. This is the result of poor cementation. It can happen in either a water or a gas. The only solution is to pull the completion , squeeze cement to block the channel and reperforate.

Notes

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FTC

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Crossflow

When more than one zone is producing commingled the pressure in each zone will change in a different manner.

Eventually one zone will be a a higher pressure and flow into the other.

The solution is to block off the problem zone or install a dual completion.

Crossflow is usually impossible to tell from surface measurements, a tool such as a downhole flowmeter is required.

The flow can go in either direction and can be substantial. If the lower zone is producing water it is possible to block it off, however if it is producing oil this will waste that production. A dual completion may be necessary.

Notes

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FTC

66


Coning

Excess drawdown and a perforation interval that is too long could lead to coning problems.

Here there is unwanted production of both gas and water.

A typical problem in a producing well. Gas can cone down from the gas cap and be produced through the upper perforations. Water can cone up. The reasons for such problems are perforations too close to the contacts or too high a pressure drawdown.

Notes

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FTC

67


Fingering

Higher permeability layers produce first bypassing some oil.

A solution is selective zone completion.

This is caused by having a number of different permeabilities in the same completed interval. The high permeabilities will be produced first caused the water level to rise there. A the point shown there will probably be only water produced as this is the high permeability layers.

Notes

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FTC

68


Stimulation

Stimulation is used to improve the permeability of the near well bore environment

There are two major methods

Fracturing

Acidising

The near wellbore is often damaged by the drilling or completion process. The objective of stimulation is to create a permanent zone near the wellbore with a higher permeability.

Notes

Fracturing creates artificial fractures to enhance production.

They are made by increasing the wellbore pressure and breaking the rock.

A proppant is used to keep the cracks open.

Only hard rocks such as carbonates, or tight sandstones are fractured.

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FTC

69


Fracturing

A Fracture is made by pumping water at a high enough pressure to crack the formation.Proppant is used to keep the fracture open.

Notes

This technique is normally carried out in carbonates, where a simple HCl (hydrochloric acid) solution can be used. The normal strength of the acid is 15%, i.e. 15% acid, the rest water.

The acid cleans up any perforation damage and adds some small pathways for flow.

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FTC

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Acid Wash

Acid is pumped into the formation. It cleans up any near wellbore damage improving the permeability.

Notes

This is a combination of both techniques. The fracture thus created is etched by the acid; there is no need for proppant.

The wing length, as with a normal fracture, is of the order of 10m.

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FTC

71


Acid Fracturing

Acid is pumped under high pressure, a fracture is created and the rock is etched creating a fracture.

drilling 1

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