BASIC DESIGN OF A WELL PRODUCTION

The basic facilities provided by a completion string must allow it to continue the production or injection of fluids over as long a period as possible without major intervention to conduct well repairs. Further, at all times, the design must ensure the safe operation of the well and reliably allow for its shutdown in a variety of situations.

The completion string, production casing and wellhead must act as a composite pressure system which prevents formation fluids and pressure escaping from the reservoir except via the production tubing and the Xmas Tree into the surface processing facilities.

The following are considered to be the essential attributes for the majority of completion string installations:

(a) The ability to contain anticipated flowing pressure and any hydraulic pressures which may be employed in well operations and conduct fluid to surface (production) or the reservoir (injection wells) with minimal flowing pressure loss and optimal flow stability.

(b) The ability to isolate the annulus between the casing and the production tubing if flow instability is likely or it is desirable to minimise reservoir fluid contact with the production casing.

(c) The ability to affect downhole shut-in either by remote control or directly activated by changing well flowing conditions, in the event that isolation at surface is not possible.

(d) A means to communicate or circulate (selectively when required) between the annulus and the tubing.

(e) A provision for physical isolation of the tubing by the installation of a plug to allow routine isolation e.g. for pressure testing of the tubing.

Consider each of the functions in turn:

(a) Pressure and flow containment
The pressure communicated between the wellbore and the reservoir is contained within the production casing, production tubing, the wellhead and the surface valve closure system known as the Xmas tree. Further, if a packer is used then reservoir or injection pressure will be retained beneath the packer.

Thus, both the casing and tubing will be designed to withstand the internal pressures which could exist in the wellbore. Similarly the wellhead, from which each casing string is suspended as the well is drilled, will be rated for maximum anticipated surface pressures. Overall control of fluid production from, or injection into, the well is provided by the valve system located on top of the wellhead. This Xmas tree usually comprises an in-line valve with a backup valve to shut in the well and side outlets with valves for both choke and kill line attachment during well killing procedures.

The production casing, packer and wellhead provide a backup to contain fluids and pressures in the event of a hydraulic failure of the tubing system.

The tubing size must be selected such that well production rates are optimised and flow is stable.

(b) Annulus Isolation
The concepts of annulus heading cycle and the potential damage which can be occasioned to the production casing, mean that a method of annulus isolation is required in the majority of production wells.

This annular isolation is normally effected by installing a packer in the completion string which is lowered into the wellbore with an elastomeric element in the retracted position. At the prescribed depth, the element is set by extrusion or inflation to fill the annular space between the tubing and the annulus. To minimise the volume below the packer and the length of casing exposed to well fluids, the packer is normally set quite deep in the well.

(c) Downhole closure of the flow string
In the event that access cannot be gained to the Xmas tree to effect valve closure and stop fluid flow or because of valve failure, it is advisable, and in most cases mandatory, to have a secondary means of closure for all wells capable of natural flow to surface. The installation of a sub-surface safety valve (SSSV) will provide this emergency closure capability. The valve can be either remotely operated on a fail safe principle from surface, or will be designed to close automatically when a predetermined flow condition occurs in the well. The initiation of the closure of the latter system will depend upon a predetermined flow rate being exceeded or the flowing bottom hole pressure declining below a pre-set level.

(d) Circulation capability
For the majority of completions a specific piece of equipment is installed to allow the opening and subsequent closure of a circulation port between the tubing and the annulus. This can be provided by installing one or more of the following devices:

(i) Sliding side door (SSD) or sliding sleeve (SS)
(ii) Side pocket mandrel (SPM)
(iii) Ported nipple

An alternative but more drastic approach would be to use a tubing punch, but since the circulation ports cannot be subsequently closed, it is only usually of use for circulation prior to a workover.

(e) Tubing isolation
This will usually be required to supplement the downhole SSSV and also is intended to provide isolation if the well is hydraulically dead and the SSSV is to be removed.

The isolation can normally be provided by lowering a plug on wireline down the inside of the tubing string until it lands and locks into a wireline nipple which was incorporated into the design of the tubing string at an appropriate depth.