Completions

Well Completions

Open Hole

The production casing is set above the zone of interest before drilling the zone. The zone is open to the well bore. In this case little expense is generated with perforations log interpretation is not critical. The well can be deepened easily and it is easily converted to screen and liner. However, excessive gas and water production is difficult to control, and may require frequent clean outs. Also the interval can’t be selectively stimulated.

Liner Completions

In this case the casing is set above the primary zone. An un-cemented screen and liner assembly is installed across the pay section. This technique minimizes formation damage and gives the ability to control sand. It also makes cleanout easy. Perforating expense is also low to non-existent. However gas and water build up is difficult to control and selective stimulation not possible the well can’t be easily deepened and additional rig time may be needed.

Perforated Liner

Casing is set above the producing zone, the zone is drilled and the liner casing is cemented in place. The liner is then perforated for production. This time additional expense in perforating the casing is incurred also log interpretation critical and it may be difficult to obtain good quality cement jobs.

Perforated Casing

Production casing is cemented through the zone and the pay section is selectively perforated. Gas and water are easily controlled as is sand. The formation can be selectively stimulated and the well can be deepened. This selection is adaptable to other completion configurations and logs are available to assist casing decisions. Much better primary casing. It can however cause damage to zones and needs good log interpretation. The perforating cost can be very high.

Conventional Completions

Casing Flow; means that the producing fluid flow has only one path to the surface through the casing.

Casing and tubing Flow; means that the there is tubing within the casing that allows fluid to reach the surface. This tubing can be used as a kill string for chemical injection. The tubing may have a “no-go” nipple at the end as a means of pressure testing.

Pumping Flow; The tubing and pump are run to a depth beneath the working fluid. The pump and rod string are installed concentrically within the tubing. A tubing anchor prevents tubing movement while pumping.

Tubing Flow; A tubing string and a production packer are installed. The packer means that all the flow goes through the tubing. Within the tubing you can mount a combination of tools that will help to control fluid flow through the tubing.

Gas Lift Well; Gas is fed into valves installed in mandrels in the tubing strip. The hydrostatic head is lowered and the fluid is gas lifted to the surface.

Single Well Alternate Completion; In this instance you have a well with two zones. In order to produce from both the zones are isolated with packers. Blast joints may be used on the tubing within the region of the perforations. These are thick walled subs that can withstand the fluid abrasion from the producing zone.

This arrangement can also work if you have to produce from a higher zone given the depletion of a lower zone. The tubing may also have flow control mechanism.

Single Well Concentric Kill String; Within the well a small diameter concentric kill string is used to circulate kill fluids when needed.

Single Well 2 Tubing Completion; in this instance 2 tubing strings are inserted down 1 well. They are connected at the lower end by a circulating head. Chemicals can be circulated down one tube and production can continue up the other.

Single Well High rate Low pressure; A packer isolates well and diverts flow through a nipple through the packer and then again diverts flow out of the tubing. Some flow is allowed to continue through the tubing. This feature is located at a shallow depth in the well.

Multiple Completions; used when multiple zones are encountered within a single wellbore.

Simultaneously Completion of all zones; several intervals are produced simultaneously in a single tubing.

Single zone completion with alternatives; production is done one zone at a time and starts with the lowermost zone.

Multiple “Reduced Diameter” Completions; Multiple completions have higher total producing rate per well bore, faster well payout. Simultaneous and/or segregated flow of fluids at different pressures.

Dual Completions Single packer & Single Tubing; The simplest configuration. The lower zone is produced through tubing and the upper zone through the annulus. The zones are separated by a packer. This method is the cheapest. However the casing is exposed to well pressure and fluids and you must kill the lower zone before working over the upper interval.

Cross-Over Dual Completion Single Tubing; this uses a flow choke or a cross-over to produce the different zones. It still exposes the casing and you need to kill the lower before working on the upper, but you can select how to produce the zone.

Dual Completion Prorated flow Single Tubing; Proration control is accomplished by regulating flow from each of the producing zones through specifically sized orifices, within dual flow choke. The two streams are then combined in the tubing above the choke. A packer may be used to protect the upper casing from exposure to well pressure. In this case both zones can be artificially lifted.

Parallel Dual Completion; This uses two tubing strings and two packers to produce two zones simultaneously. Separate flow can be achieved from each tubing and each zone can be achieved from each tubing and each zone can receive selective artificial lift control. However it is more expensive and workovers are more difficult.

Parallel Dual with Alternative Completions; Installed in both long and short string completion. Triple completions use two or three tubing strings and packers. Achieves high yield per well but difficult to install.

Tubing less Completions; miniature versions of conventional configurations. This is an attempt to lower cost and to be able to work over wells selectively. They are easier to install. Lower productivity, stimulation rate, corrosion problems and the inability to get a good primary cement job are the down sides of this method.

Single Flowing Well; Miniaturized version of single tube “perforated” casing. A landing nipple is used for safety valve service.

Single and Dual Completions; Combination tubing less completion with variation. Single and dual flow artificial lift perforated and un-perforated.

Triple Completions; Comparable to conventional triple completion. However the casing is removed and the packers replaced by cement.

The ESP

The typical pump consists of –

  1. The electric motor section
  2. The seal section
  3. The intake section
  4. The multi-stage centrifugal pump
  5. The electric cable
  6. Surface installed control panel and complementary equipment.

The electric motor is usually a 2 pole, 3 phase squirrel cage induction motor. The horsepower is obtained by increasing the motor length and the number of rotors.

The seal section does four main functions.

  1. Houses the axial thrust bearings
  2. Prevents the entry of well fluid into the motor
  3. Equalizes the pressure between the motor and the well bore
  4. Compensates for expansion and contraction of the motor during operation.

Intake section/Gas separator is essentially a suction manifold that is attached to the pump intake section in the event that a high amount of gas is expected.

Multi-stage centrifugal pump have two main parts. The parts are an impeller and a diffuser. To get the high pressures needed then several sections can be attached/stacked together. The impeller can be either fixed or floating. The floater, the impellers can move axially along the shaft. In a fixed pump the impeller is fixed to the shaft. Wear on the pump parts is considerably reduced in a fixed pump.

The thrust developed by the impeller is dependent on the design and operating point of the pump.

The maximum size of the pump is determined by:

  • Horsepower rating of the pump shaft
  • Pressure rating of the pump housing
  • Load carrying capacity of the thrust bearing

Check and bleeder valve installed 2-3 tubing joints (20-30m) above the pump assembly. It helps to maintain a fluid head above the pump. If the check valve is not there then their can be reverse circulation and rotation of the motor. They are combined with a bleeder valve to prevent pulling a string with fluid.

Electric cable is run to power the device in the wellbore. The cable is usually round and is sized for the power requirements of the pump.

Surface equipment usually includes the electrical and standard control panels that house the electrical control, interface and safety equipment.

Perforating

This is done to provide affective flow communication between reservoir and wellbore. The perforating jobs is irreversible and as such requires good planning.

The shaped jet perforator is mechanically simple and reliable, with generally higher performance. Suits a wider range of completion needs.

The wireline methods have offered depth control, selective firing speed and low cost.

Shaped charge – these used shaped charges and special “quick” explosives (PDX-Cyclonite) to pierce the tubing casing to make the perforations. This type of propellant is faster than that used in bullet guns. Penetration times are about 100-300 microseconds.

The charge may be lined or unlined. The lined charge is deeper but narrower than the unlined. The liner is usually copper.

The primer is initiated this then detonates the main charge. The detonation wave causes the liner to disintegrate and form a jet then penetrates the casing. Not all of the liner goes into the jet. ½ goes into the jet and the other forms a slower moving slug section within the jet. Since the slug moves slower and behind the advanced jet it can plug the perforations as such new technologies have developed liners that disintegrate better or vaporize so as to not form a slug.

Gun Categories –

  1. retrievable hollow carrier
  2. Non-retrievable/Expandable

The retrievable hollow carrier – this is a hollow tube to which the charges are secured. The charges are surrounded by air at atmospheric pressure. The charge then fires but the debris fall within the carrier wall and can be fully retrieved from the well.

The non-retrievable – consists of individually pressure sealed cases. There is no carrier to contain the blast. Everything disintegrates and the debris remains within the well. Good gun to casing clearance is ½”.

Semi-Expendable guns

  • Have minimum amounts of debris
  • Improved debris character
  • Improved pressure capability
  • Facilitates 0° phasing

Retrievable hollow Carrier

  • High reliability mechanically strong/rugged
  • Fast running high pressure and temperature
  • No debris, easily adaptable to desired shot density
  • No casing deformation, high charge performance
  • Gas tight and resistant to well bore chemicals

The only upside to fully expendable guns is that they are cheap and they can be hooked together to form longer lengths.

  • Flexibility permits handling long lengths
  • Can deform casing when fired
  • Leaves debris in the well
  • Explosive components are exposed to the wellbore environment
  • Not gas proof, and can’t resist acid
  • Not mechanically competent, prone to wear
  • Low tolerance for high pressure and temperatures

They are used in shallow holes that don’t tax their mechanical and operational abilities.

The number and size of the shots are governed by hydraulic considerations i.e. differential pressure, flow rates etc. Some give you the option to fire selectively by carrier or shot by shot.

Limited penetration devices are used to perforate tubing or drill pipe without damaging casing. This is done to establish circulation or squeeze cement. In some cases shaped charges are used to cut the casing. In most cases casing cutters are expendable and tubing cutters are retrievable.

Hydraulic perforators use fluid laden with sand to punch a hole in the casing. Their operation is timely and costly. Mechanical perforators use a mechanical means to create a hole, used even less than hydraulic methods for the same reasons.

Depending on the type of explosive damage may be done to the casing. It may result in hairline fractures or a split in the casing. Hydrostatic pressure minimizes deformation but cement strength has little effect on casing deformation. However deformation increased with increased cement thickness. Expandable gun type perforations should be avoided in old wells where casing may be damaged by corrosion.

Perforation Guidelines

  • Shot density is of greater importance than penetration depth
  • Penetration depth is important if there is skin damage
  • The penetration has to be able to go beyond the skin damage to be productive
  • Positive pressure perforation is done when perforating in drilling mud. In this case the mud may plug the perforations.
  • Reverse pressure is for perforating with a lower pressure within the well bore. In some cases perforation is conducted in a clean fluid/acid to enhance perforation.
  • To minimize rig costs remove rig from the well and perforate through tubing.
  • Shoot through tubing at reverse pressure.
  • Utilize a positioning device to assure gun performance.
  • Avoid mud shooting, use salt water, oil or completion fluid.
  • Use modern designs for the best/cleanest perforations.
  • Gun size and type should satisfy the well conditions.
  • Use the appropriate well head pressure control equipment.
  • Insist on good depth control techniques to ensure that perforations are placed correctly.
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