Production testing requirements

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Production testing may cover a whole range of operations and involvement of a number of services and equipment contractors. In the following, general requirements to the outline, execution and follow-up of the operations are defined.

General Production Test Outline

1) Perforate the casing across the test interval or clean up the wellbore in open-hole testing. (Will be done prior to completion).

2) Determine the initial reservoir pressure.

3) Unload the well.

4) Flow the well at a stable rate.

5) Shut in and record build-up.

Operational Priorities

The production test operation is supervised and co-ordinated by the Senior Company Drilling Supervisor. However, in matters relating to the safety of the installation and personnel, the Offshore Installation Manager is the final authority.

During stable flowing periods, the arrival and departure of helicopters on offshore installations will be at the discretion of the pilot in consultation with the Offshore Installation Manager.

Completion String Safety Valves

On platforms, the completion shall include a subsurface safety valve which will be surface controlled and fail-safe closed.

Surface Process Equipment Outline

The minimum requirements for a platform welltest surface process outline shall be Pipework, Hoses, and Choke Manifold with minimum working pressure ratings in excess of the maximum anticipated closed in tubing head pressure (C.I.T.H.P.).

In addition, the flow process downstream of the choke manifold will be directed to a suitably located effluent burner and may be directed via an indirect heater, a separator and/or a surge/stock tank.

The above listed equipment shall be suitable for sour service.

Flowing

a) Unloading the well at a high rate improves clean-up. However, draw down may have to be limited to avoid sand production. The well is considered cleaned up when the Base Sediment and Water(BS & W) do not further decrease, and the well flows at a stable rate with a stable gas/oil ratio, at a stable or slightly declining tubing head pressure (HP).

b) There is no need to flow at maximum rate, as long as the rate is stable and supercritical (i.e., HP upstream of choke at least twice HP downstream of choke). It may be required to shut in the well unexpectedly before the programmed flow period has been completed (e.g., due to a leak in the surface lines). In some cases, it may then be preferable to leave the well shut in and monitor the build up, rather than re-opening the well, to complete or re-commence the flow period.

c) If build-up information is required leave the well undisturbed. Do not pressurise or bleed-off the annulus, and do not inject methanol/glycol. However, if forced to change the conditions, report this clearly.

d) The well will often need conditioning prior to sampling to ensure representative samples are taken. During the preceding flow period, the well may be producing below bubble point, resulting in gas break out. The well should be produced at a low rate to ensure excess gas is removed from the well/near well bore prior to sampling.

e) Occasionally, it may be required to flow at maximum rate. This rate is defined as the flow rate at maximum choke size at which flow remains critical (HP upstream of choke is twice the downstream pressure).

Emergency Shutdown

The surface equipment shall be protected by a shutdown valve upstream of the main choke manifold as close to the Xmas tree as possible. This valve shall be fail-safe closed and remotely operated from positions on the drill floor, test area, and at least one other location in a safe area.

Each section of the flow process, whose maximum operating pressure is less than the closed in tubing head pressure shall be protected by a relief valve upstream of each pressure/specification change. Also, at these pressure/specification changes there shall be a high pressure pilot linked to the automatic shutdown valve mentioned above.

Well Treatments

Stimulation treatments shall only be carried out under conditions where there is sufficient natural or artificial light to clearly observe all process and flow line connections.

Testing With H2S In The Fluid

Where there is a likelihood of producing well fluids containing H2S, specific Compamy measures shall be implemented.

For the purposes of testing reservoirs containing H2S, all areasof the installation where there is an immediate danger of high levels of H2S shall be classified as  potentially unsafe breathing areas, e.g., test site and drill floor.

In areas classified as potentially unsafe breathing areas, the minimum precautionary actions shall be governed by the worst anticipated concentration of H2S possible in the atmosphere.

Hydrate Prevention

The only Glycol used in well testing shall be Mono-ethylene.

Glycol/methanol shall be injected at all times when running wireline in any well which may be considered as a wet gas environment.

Methanol shall always be injected at the Xmas tree during start up of any flow period.

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