SECTION 7 Well Test System

701. General

1. Well test systems are the facilities installed on units for the purpose of evaluating the quality and/or quantity of the well fluid to determine whether the well is to be completed for production or plugged and abandoned.

2. Well test systems consist of well control equipment, process pressure vessels, piping and electrical components, control systems, burners and gas flares and burner/flare booms.

3. Systems mounted permanently for at least 30 months on the unit and are intended for extended tests or early production are also to comply with Guidance for Floating Offshore Production Units.

4. Temporary well test system (for less than 30 months), including burner booms, burners, well test equipment, process pressure vessels, piping, burners and gas flares, and control/safety systems are also to comply with the requirements of this Section.

5. In addition to the requirements of this Section, skid-mounted packaged equipment is to be in ac- cordance with Sec 10.

6. Individual well test equipment and skid-mounted equipment structural interface with the drilling unit is to be verified for structural adequacy in accordance with the Rules.

702. Well test system

1. Well control equipment such as flowheads, test trees and emergency shut down valves are to be suitable for the intended pressure. Design and fabrication are to be in accordance with recognized standards such as API Spec 6A, API Spec 16C, API Spec 6D, and API Spec 6AV1.

2. Pressure-retaining equipment such as separators, heaters, treaters, nitrogen storage, surge and transfer tanks, etc., are to be in accordance with Sec 8, 801.

3. At least two (2) relief valves or the equivalent are to be provided on test separators. The relief valve vent lines are to be led outboard at least 120 pipe diameters or connected to a suitable hy- drocarbon disposal facility in accordance with 703. 2.

4. Well test oil/gas separators are to be in compliance with the requirements of API Spec 12J.

5. Piping systems are to be in accordance with Ch 5.

6. Materials are to be in accordance with Ch 3, Sec 1.

7. Welding and non-destructive examination are to be in accordance with Ch 3, Sec 2.

8. Flexible hoses are to be designed and constructed in accordance with Ch 5, 204.

9. Pumps handling hydrocarbon pumps are to be in compliance with the requirements of API Std.

610.

10. Control systems are to be in accordance with Ch 6, Sec 2.

11. Electrical components are to be certified for use for their intended service and classified areas as outlined in with 703. 5. Electrical installations are to be in accordance with Ch 6, Sec 1.

12. The well test system burner/flare boom structure is to be in compliance with 703.

13. Skid structures are to be in accordance with Sec 10.

703. Burner/Flare booms

1. Design loads

(1) The loads to be considered in the design of a boom structure are to include:

(A) Dead weight of structure, piping, fittings, rigging, snow and ice, walkways, guard rails, etc.

(B) Wind loads

(C) Thermal and impulsive loads resulting from the use of the flare

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(D) Vessel motion-induced loads

(2) The values of all design loads are to be listed in the submitted design documentation.

(3) Loads resulting from vessel motions and wind loads can be established using the procedures given in API Spec 4F.

(4) The derivation of loading conditions to be used in the design is to give due account of the op- erational requirements of the Owner, and are to reflect both the operational and stowed modes

of the boom.

2. Hydrocarbon disposal facilities

(1) The sizing and design of the hydrocarbon disposal equipment (flare, flare tips, scrubber, piping, pump, atomization equipment, etc.) are to follow the principles of API Std. 521.

(2) Two (2) flares are to be provided on opposite sides of the installation to dispose hydrocarbon

in an appropriate downwind direction.

(3) Flares and burner booms are to be arranged such that the incident heat on critical surfaces does not exceed 1500 BTUÕhrÕ ftĪ.

(4) In cases where crude oil is burned and atomization is used, atomization medium supply lines are to be provided with a non-return valve or some other approved means of preventing back- flow of hydrocarbon into nonhazardous piping systems.

(5) Gas flare tip flow rate is generally not to exceed 0.5 Mach. (See API STD 521).

3. Surface safety systems

(1) A system of automatic and manual controls together with shutdown and operating procedures are to be provided in accordance with the principles of API RP 14C with due consideration given to the normal manning during well test operations.

(2) The following specific requirements are to be applied.

(A) Process system pressure, level and temperature are to be monitored.

(B) Gas detection is to be provided in process areas.

(C) Visual and audible alarms are to be set at 20% and 60% lower explosive limit and in the presence of H2S 10 PPM and 15 PPM.

(D) Fire-fighting equipment is to be adequate to water deluge process components with at least

10.2 • per minute per square meter of component surface area.

(E) The arrangement of process components onboard is to allow for complete access to process

controls and ingress for fire extinguishing agents.

(F) H2S gas detection systems are to be provided.

(G) Each well injection line is to be provided with a check valve located at a flowhead or test tree.

4. Hazardous areas

(1) Hazardous areas are to be in accordance with Ch 7 of the Rules and API RP 505.

(2) Hazardous areas are to be in accordance with the following requirements.

(A) Hatches, companionways and ventilators within ten feet of classified areas are to be secured gas tight for the duration of the test program.

(B) Electrical equipment within classified areas is to be suitable for the hazard or de-energized.

(C) Areas around valves and ball and socket hammer unions are to be designated as Zone 2 for a distance of 1 m.

(D) Fired heaters and diesel driven machinery are to have air intakes located at least 3 m from any classified area.

(E) Exhausts are to be equipped with spark arresting devices and are to discharge outside classi- fied areas.

5. Operational procedures are to be submitted to the Society and are to include the following.

(1) Production test plan

(2) Manning requirements

(3) Equipment operations and testing procedures

(4) Process startup and shutdown procedures

(5) Fire-fighting procedures

(6) Emergency evacuation procedures

62 Guidance Relating to the Rules for the Classification of Mobile Offshore Drilling Units 2015