05 well completion

Well Completion and Intervention

Operations Training(RTC)

After the well is drilled, casing ran and cemented in place, the well is ready for the completion process to begin.

Well completion may be performed by the larger drilling rig or by a smaller less expensive completion/workover rig. Rig type would be determined by availability and project economics.

The uncompleted well is not perforated and is left with the casing full of liquid. It is capped off with a valve.

To complete the well, it must be perforated, sand control installed if required, the tubing installed, tubing auxiliaries and packers installed and the tree installed.

The first step in the completion process is to remove the valve and flange and install the workover BOP on the well.


A completion/workover rig is similar to a drilling rig but on a reduced scale. Completion/workover rigs have four basic systems.

1. Power System

2. Rotating System

3. Hoisting

4. Circulating System


Shale Shaker

Diesel Tank-Skid Beams

Engines

Derrick

Skid-Beam

Draw Works

Work String

Elevators


CameronType UPreventer with Blind Rams

CameronType UPreventer with Pipe Rams

Preparation Steps Completing a well:

1. Installing the blowout preventer

2. Filling the well with proper completion fluid

3. Perforating the well

4. Installing sand control equipment if required

5. Running product tubing with its auxiliary components

6. Pumping inhibited fluid in to the annulus when required

7. Removal of the BOP stack and installing and testing the Christmas Tree.

7 1/16”/179 mm Hydril Annular Preventer

Blind Rams

Pipe Rams

Cameron Type U Preventer

The type of well completion needed is dependent on several factors.

•Zone Thickness: A few feet to hundreds of feet/hundreds of meters.

•Reservoir Pressure: Almost zero to more than 20,000 psi (1,406kg/cm2 ).

•Reservoir Temperature: 60 ° F (16 °C) to 600 °F (315 °C) or more.

•Contaminants: Compounds like H2S and CO2 are annoying in small amounts. In higher volumes it may require special equipment and procedures. Above a certain point, it may not be economically feasible to produce some zones, because of these components.

•Unconsolidated Sand

•Water productionOperations Training(RTC)

Wells that are completed in hard rock formations or sands that are naturally cemented together do not require sand control.

Well completed in a sand zone that has not been naturally cemented together, (unconsolidated sand) would flow to the surface with the produced fluids and cause serious problems.

Sand control, usually in the form of a gravel pack or pre-pack screens are used to keep the sand in place.

• After a well is drilled and cased, equipment is installed to flow oil and gas from the reservoir to the separation equipment. The “completion” procedure varies with depth, pressure, expected flow rates and other factors.

• A successful well is the result of a combination of good drilling, completion, and production practices. Failure in any one of these area’s could affect present or future project development.

• Poor drilling practices could result in formation damage, reduced flow rates and possibly premature well abandonment, which in turn would effect ultimate recovery.


Completion Steps

A bit and scraper run is made to insure no cement deposits were left on the interior walls of the casing.

If drilling mud was left in the well after the drilling process, it is replaced with completion fluid.

If the well is not to be an open hole completion, the next step may be to perforate the well and run the production packer.

If the well is to be a gravel pack completion, a sump packer set , the casing perforated, a screen and packer installed, and gravel pumped.

Open hole completion wells are completed by drilling out of the end of the casing. The target zone is penetrated, a pre-pack screen is installed in the un-cased hole which is anchored and sealed in the casing.

Work String Or Drill String

Scraper

Bit

The rig will pick up a drill string or a work string and make a bit and scraper run to TD. This is to ensure that the well bore and casing is clean to TD.

At this point, the liquid left in the casing by the drilling rig will be displaced with a specified completion fluid.

Casing Scraper

Loose unconsolidated reservoir sand will flow up the tubing string along with reservoir fluids unless restricted from doing so. Unconsolidated reservoirs requires some type of sand control.

There are typically three types of sand control.

Sand consolidation - gluing of reservoir sand grains together.

Gravel pack - filter system usually required in high volume wells with large producing intervals. A gravel pack is designed for the sand characteristics of a specific reservoir. This system prevents loose reservoir sand from flowing into the well.

Pre-pack screen - This system incorporates a sand

filtering material which is wrapped between an

inter and outer layer of the screen.

HES

Pre-pack

Screen

The first step in a gravel pack completion is to set the sump packer.

This packer is set for two reasons.

1. It will be the basis for proper placement of the gravel pack screen across the perforations. For accuracy in packer placement, an electric line unit is used to set this packer.

2. Sand grains and/or other particles that pass through the screen fall through the bottom of the gravel pack assembly into a sump or rat hole. This lessens the chances of plugging the tubing.

Locating Device

Packer Setting Tool

Sump Packer

Sump/Rat Hole

Perm. Packer

Packer Seal Assemblies

Once the sump packer is set, the well will be perforated. This may be done with tubing conveyed guns or guns run on electric line units. Perforating guns are designed to penetrate the casing, the surrounding cement, and go into the formation, opening the reservoir to the well bore. Perforating guns usually do their job by means of a shaped explosive charge.

Caution: Perforating is a critical and potentially dangerous operation, all guide lines must be followed.

This process may leave behind undesired material that could impede flow into the well bore.

Sump Packer

Perforations

Locating Device

r


Perforation Guns

Pictured to the right are casing and tubing perforators.

Tubing conveyed perforating gun

Wireline conveyed perforating guns


Perferation:

After casing is set and cemented, the well must be opened to the producing zone. Necessary holes are opened through the casing and cement into the producing zone.

The perforating process may leave material behind which may affect production volumes, the well is usually back surged to remove this material.

A back surge tool is run and set above the perforations.

The back surge process causes a sudden short term decrease in pressure at the perforations. Damaged material in the perforated areas caused by the shaped charges are pulled into the casing by the reduced pressure.

This material is circulated out of the well, it’s volume measured and an equal volume of clean gravel pumped into the well.

Next, the screen and gravel pack setting and crossover tool are run. The gravel pack sand is pumped in a gel type solution. This solution is designed to keep sand volumes consistent as it is pumped down the work string.

Once the sand /gel slurry is pumped below the screen liner hanger, it goes through a port in the crossover tool into the annular space between the screen and production casing. The gel minus the sand returns to the surface through a port in the gravel pack assembly by crossing over into the production casing /tubing annulus.

Pumping continues until pack sand fills the annulus between the production casing and the screen to a predetermined height. The gravel packing is now complete.

The liner setting device and gravel pack tool are pulled out of the hole.

Sump Packer

Perforations

Screen

Liner Hanger

Gravel Pack

Crossover

Tool

Screen Liner Hanger Packer

After the gravel pack running equipment is removed, the complete gravel pack assembly including the sump packer, sand screen, sand and liner hanger/packer will be in place.

The well is now ready for the production tubing and its components to be installed.

The production tubing which carries fluids from the reservoir to the christmas tree is now installed. Tubing strings generally run from 2 3/8 “ to 5 1/2” in diameter. The tubing string contains a number of auxiliary devices which provide safety and environmental protection and assist in producing and maintaining the well.

Landing Nipple

Gas Lift Valves

Landing Nipple

Surface Controlled Subsurface Safety Valve And Hydraulic Control Line

Proposed Completion Sketch

Auxiliary Tubing Devices

Landing nipples - Equipped with a polished bore and internal profiles cut into the I.D., these devices allow locking mandrels and the attached devices to be locked and sealed in the tubing.

Locking mandrel are flow through devices.

Landing nipples and Locking Mandrels may be used to:

•Check tubing integrity.

•Install a down hole choke.

•Install a subsurface controlled safety valve.

•Hang off a BHP device.

Landing Nipple

Gas Lift Valves

Landing Nipple


Landing Nipple

Locking Mandrel


Gas Lift Mandrels: High pressure compressed gas from the production casing is injected through the mandrel and gas lift valve into the tubing.

Gas injection lightens the hydrostatic fluid column in the tubing, allowing the well to flow.

Some wells are kicked off on gas lift, others require gas lift continuously. To date Shell has not used gas lift in any deepwater or subsea wells.

Other methods of artificial lift are:

•Rod pumping

•Hydraulic down hole pumping

•Electrical down hole pumping

Landing Nipple

Gas Lift Mandrels

Landing Nipple


Landing Nipple

Gas Lift Valves

Landing Nipple

Subsurface Safety Valve And Hydraulic Control Line

Rod PumpHydraulic Pumping Systems

Surface controlled subsurface safety valves:

Usually part of the tubing

Automatically closes if a undesirable event or catastrophe occurs.

Set at least 100’ below the mud line (MMS). Fail safe; normally closed valve

Operates automatically or manually

Controlled by a small stainless steel hydraulic line which allows hydraulic pressure from the surface to operate the valve.

The valve must be checked for holding every 6 months (MMS).

Chemical injection Nipples:

Allows injection of chemical down hole into the tubing.

If necessary, injection of hydrate inhibition chemicals, asphaltine inhibition chemicals, wax (paraffin) control chemicals, and corrosion inhibitors can be injected into the tubing.

Down hole pressure /temperature devices:

Provide real time wellbore pressures and temperatures.


Down hole volume measurement devices:

- Usually run in high volume subsea or TLPs wells.

- Permits down-hole measurement of produced fluids.

- Eliminates large heavy top side measurement equipment.

- In multiple subsea systems, will reduce down time due to testing.

- Allows measurement before commingling subsea wells


Surface CasingLanding Base

Conductor Casing

Production Casing

Slip and seal assembly

Production Tubing

VR Plug Valve Removal

Tubing Hanger Spool

Tubing Hanger

SC-SSSV HydraulicControl Line

Drive Pipe

Hanger Pins

Guide Pins

Christmas Tree


Typical Solid Block (OCS) Tree

Tree Cap

Wireline Valve

SSV

Master Valve

Tubing Hanger Spool

Casing Valve

Choke Body

Needle Valve

Wing Valve

Subsea Tree

•Choke

•POD (Subsea Control Module)

•Tree Valves

•Production

•Chemical

•Annulus

Tree

Wellhead

ROV Access Panel

POD (Control Module)

Subsea Tree

Tubing Head Assembly

Tree Cap

Tubing HangerTubing Hanger

ROV Tree CapROV Tree Cap

Insert ChokeInsert Choke

Tree AssemblyTree Assembly

Tubing HangerTubing Hanger

Vertical HubVertical Hubfor Well Jumperfor Well Jumper

Tubing HeadTubing HeadAssemblyAssembly


After a well has produced for a time, mechanical may develop.

Problems may include:

A. Damaged Tubing•Collapsed and plugged •Holes and split •Parted and corroded •Leaking Packers

B. Damaged gravel pack screens• Collapsed• Washed out

C. Damaged Casing• Collapsed• Split• Eroded• Parted• Corroded

Remedial Well Operations

Remedial well work will be required at some point in the life of a well.

Re-completions requires a workover rig.

If the job does not require pulling of the tubing, through tubing equipment may be used.

Problems may include:•The reservoir is depleted

•Excessive gas or water production

•Mechanical problems

•The well is plugged up


Mechanical problems (Tubular Damage) usually require pulling the tubing string and its components, necessary repair’s or replacement made and the well returned to production. With this type of workover, the well continues to produce from the same reservoir.

Examples of non-mechanical well problems:

1. Excessive water production (expected or unexpected)

2. Excessive gas production

3. Restricted production due to formation damage

4. Increase/decrease in reservoir pressure

5. Depleted reservoir


Conventional Workover/Intervention Methods:

• Require removal of Christmas tree, tubing, and other mechanical components in the well

• In many instances, workover/intervention on a well with reservoir problems will require completing the well in a different reservoir

These projects must be justified, cost to do the work is estimated, economics of the project are then determined. Based upon this evaluation, the project is approved or rejected.

After completion, the well is turned over to production for unloading and bringing to full potential.

Coiled Tubing Units A continuous small diameter tubing (generally on the order of 1/2” to 1 1/4”/12.5mm to 31.25 mm in diameter) which is inserted into and removed from the well bore by means of a tubing injector and BOP which is mounted on the christmas tree.

Designed to do remedial work on wells without removing the christmas tree or production tubing from the well.

They are limited in the following ways:•Depth and pulling capabilities•Pressure handling capabilities•Inability to rotate the work string•They must use down hole mud motors to drill•Do not work well in highly deviated wells•Not well suited for minor drilling or fishing operations

Courtesy of Halliburton Energy ServicesCourtesy of Halliburton Energy Services

Snubbing Units

Designed to do remedial work on a well without removal of the Christmas tree or production tubing. This kind of a project is called a through tubing job. Pipe, generally about 1”/ 25 mm in diameter is inserted into and removed from the well by means of a hydraulic ram. A small BOP is placed on top of the tree to ensure proper well control while working is being conducted. Snubbing operations are suited for work on fairly deep high pressure wells.

Snubbers are capable of:•Acidizing wells•Drilling or washing sanded out of the tubing•Fishing operations including milling•Minor drilling operations by means of a hydraulic rotating system or a down hole mud motor.•Operating in deviated wells.•Unloading wells by means of gas injection•Spotting cement and doing minor squeeze jobs Courtesy of Halliburton Energy Services

Down Hole

Mud Motor

To recomplete this well to another zone:•A workover rig would be moved on location•The well would be killed and prepared for the workover•The tubing would be removed•If the zone to be completed were below the existing zone, the gravel pack would have to be removed using typical fishing techniques to clean out the hole.•The perforations would be squeeze cemented•The new zone would be perforated and gravel packed•Production tubulars would be run in the well•The christmas tree installed and the well would be turned over to production personnel to be put on production

If the zone to be completed were above the existing zone, the gravel pack would be squeeze cemented and abandoned using typical cementing techniques.

The new zone located above the original zone would be perforated and gravel packed

•Production tubulars would be run in the well

•The christmas tree installed and the well would be turned over to production personnel to be put on production

Squeeze Tool

Packer Mill and Spear

Box and Tapered

Taps

Junk and Tapered

Mills

Rotary

Shoe

Surface Controlled Subsurface Safety Valve System

SC-SSSV


• Surface controlled subsurface safety valves are controlled (opened & closed) from the surface by applying and releasing hydraulic pressure to the valve.


• The Surface Controlled Subsurface Safety Valve is a device installed in a well to prevent uncontrolled well flow when actuated.

• This type valve can be tubing or wireline retrievable.


• Each well has both a surface safety valve (SSV) and a surface controlled subsurface safety valve (SC-SSSV)

• The SSV is the primary means of shutting in the well

• The SC-SSSV is the secondary means of shut in


Regulations concerning subsurface valves• All tubing installations open to

hydrocarbon-bearing zones shall be equipped with subsurface safety valves

• All tubing installations which are capable of natural flow shall be equipped with a surface control SSSV


• Test frequencies: Every six months

• Leakage rates: 200 cc’s liquid per min. or 5 scfm gas

• The SC-SSSV shall close in not more than 2 minutes after the shut in signal has closed the SSV

Surface Safety Valve System

Subsurface Safety Valve

Subsurface Controlled

Subsurface Safety Valves

SSSV


The subsurface controlled subsurface safety valve (SSCSV) is a device installed in a well, below the well-head, with the designed function to prevent uncontrolled well flow when actuated.


• These devices can be installed and retrieved by wire-line (wire-line retrievable) and/or pump down methods (TFL Thru-Flowline) or be an integral part of the tubing string (Tubing retrievable).


• The most common type in our operation is the wire-line retrievable, which is set in a landing nipple or on a slip lock device. The landing nipple is generally used. The subsurface safety valve is attached to a mandrel which is located, locked, and sealed inside the landing nipple. A flow coupling should extend a min. of 3 feet above and below the landing nipple.


• Other names given this valve are “storm choke” or “velocity valve”. The general principle of operation is an increased pressure drop across the choke or decreased tubing pressure that will cause the valve to shut.


• These valves are set to close on velocities higher than normal production rates. This is generally done by installing spacers and chokes in the valve. If improper spacers or chokes are installed, the valve will not close at the desired velocity.


• Leakage Rates: 200 cc liquid or 5 scfm

• Test Frequency: Every six months if not installed in a landing and once a year for those valves that are installed in a landing nipple.

05 well completion

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