This article describes the Completion design considerations.
Reservoir considerations
Reservoir drive mechanism may determine whether or not the completion interval will have to be adjusted as gas-oil or water-oil contacts move. A water drive situation may indicate water production problems. Dissolved gas drive will result in pressure depletion and may indicate artificial lift. Dissolved gas and gas drive reservoirs usually mean declining productivity index and increasing gas-oil ratio.
Secondary recovery needs may require a completion method conducive to selective injection or production. Water flooding may increase volumes of fluid to be handled. High temperature recovery processes may require special casing and casing cementing materials.
Stimulation may require special perforating patterns to permit zone isolation, perhaps adaptability to high pressure and/or injection rates, and a well hook-up such that, after the treatment, the zone can be returned to production without contact with kill fluids.
Sand control problems alone may dictate the type of completion method and maximum production rates. On the other hand, reservoir fluid control problems may dictate that a less than desirable type of sand control be used (e.g. a resin consolidation process rather than a gravel pack to facilitate inflow profile, hence, GOR control).
Multiple reservoirs penetrated by a well pose the question of single or multiple (selective or commingled production) completions and often dictate a completion conducive to wireline or through-tubing type recompletion systems to simplify and reduce workover frequency and cost.
Artificial lift may mean single completions even where multiple zones exist, in addition to using larger tubulars than would be needed for natural flow.
Drilling and completion process considerations
- Minimise or eliminate formation damage, i.e. underbalanced operations.
- Poor quality cementations can lead to annulus pressures and loss of well integrity.
Casing design
The casing design should specify the minimum casing diameter and the maximum casing shoe setting depth for all strings.
The inflow system
The interface between producing formation and wellbore/producing conduit defines the inflow system of the well completion.
The outflow system
The well outflow system defines the flow path within the well completion, from inflow element within the production casing/liner to surface. It includes the tubing, tubing accessories, safety devices, artificial lift or pressure boosting facilities (within the well) and Xmas tree. This will determine the maximum production/injection rate.
Selection and specification
- type of well
- design life
- well configuration
- reservoir
- operating conditions
- artificial lift requirements
- well intervention techniques
- equipment features
- equipment housing
- valve/packer and equalising systems
- hydraulic actuation systems
- lock-open and insert systems
- development status
- field experience
Standards and quality
API and ISO specifications
Safety aspects
Where it is possible for equipment to have a fail-safe capacity, such as subsurface safety valves, this feature should be specified.
The degree of well protection required is determined by the following factors:
- production potential of well
- the potential danger to life, the environment, equipment and reservoir
- the probability of loss of control occurring
- the ease and cost with which control can be restored.
Well killing philosophy
Potential problems should be identified, and the findings incorporated in the well design. Design considerations should include:
- ·Kill method. Bullhead (minimising the requirements for downhole communication devices, and hence potential leak paths, or reverse circulation (minimising potential damage to the formation).
- ·Requirement for permanent facilities, i.e. provision of a kill valve or kill connection at the wellhead. Offshore, permanent pipework from the well to a kill facility/boat deck connection may be necessary.
Annulus/tubing seals
Apart from the tubing head and the integrity of the tubing and connections, sealing between the casing and tubing rests with the packer and the sealing elements in such equipment as anchor seals, locator seals, telescopic/swivel/travel joints, tubing seal receptacles and sliding sleeves.
A packer is a subsurface tool used to provide a seal between the tubing and the casing (or wall) of a well and is generally located immediately above the reservoir concerned. This seal prevents vertical movement of fluids in the annulus, and thus provides a means of production control.
Seal elements can be in the form of 'O'-ring moulded elastomer seals or chevron seals ('V'-packing).
In gas wells with low differential pressure across the packer, the use of moulded seals on anchor seal assemblies is generally recommended, but these seals are made of Hycar and should not be used in high condensate ratio wells. Moulded seals should not be used on dynamic seal assemblies.
Consideration must also be given to the question of stabbing downhole, whether it is more desirable to stab:
- a component with external seals into a polished bore receptacle, or
- a component with internal seals over a polished mandrel.
Circulation and communication devices
Circulation and communication devices include sliding sleeves, side-pocket mandrels and ported nipples. Both side-pocket mandrels and ported nipples require insertion of a valve or other device before they become operational. These should be selected for their specific function, and whether they are used for automatic (usually pressure) or wireline operation.
Side-pocket and ported nipple equipment have the advantage that the elastomer can be retrieved and replaced with the sleeve/valve by wireline methods.
Where practical, corrosion resistant (CRA) alloys instead of chemical injection. The simpler the design the less well intervention requirements.
Tubing
The selection of a tubing string requires the specification of:
- material selection
- thread/connection type
- operational parameters
- dimensions.
A number of computer-based packages have been developed to allow optimisation of the tubing size selection and configuration based upon matching the inflow and tubing performance relationships.
Blast joints are universally recognised for protection from external erosion.
Flow couplings above and below turbulence-inducing equipment can reduce the rate of internal erosion
13 Cr materials are more susceptible to HCl corrosion, and inhibitors used for carbon steel tubulars are not effective on stainless steel tubulars.