ISO 13501:2011 pdf free download – Petroleum and natural gas industries一 Drilling fluids一Processing equipment evaluation.
7.5 Operation of shale shakers
7.5.1 Inspect the screens every time circulation is interrupted.
7.5.2 Never bypass the shale shaker(s) while circulating or on trips into the hole. This includes dumping the rear tank into the active system.
7.5.3 Screen all fluids, including that shipped to the rig from elsewhere, before they enter the active system tanks.
7.5.4 Spray bars should be used only when required for the handling of gumbo or sticky clays. The orifices or jets on the bar shall be small enough to deliver water in a mist, rather than in a spray.
7.5.5 Use the shaker screens with the smallest openings that do not cause excessive drilling fluid loss.
7.5.6 Under normal operating conditions and when using a single-deck shaker with multiple screens, all screens shall have the same API designation (as defined in Clause 11).
7.5.7 On double-deck shakers with flow in series through the two decks, the top screen shall always be coarser than the screen in the lower position. A difference of two API designation sizes is generally effective.
7.5.8 Replace or repair promptly all torn or damaged screens.
7.5.9 Do not routinely operate adjustable deck shakers in the maximum upwards position. This practice will cause degradation of cuttings, and on some shakers permit fluid to spill over the back of the screen bed.
7.5.10 Screen selection with weighted drilling fluids involves a compromise to accommodate the need to maximize cuttings removal while not separating excessive quantities of weighting material. Usually an API 200 size screen is the finest shaker screen that does not remove excessive quantities of weighting material (i.e. barite).
NOTE Some weighting material loss is inevitable when screening weighted drilling fluids. Drilled solids retain drilling fluid as they leave the shaker screens.
7.5.11 Observe the manufacturer’s recommendations on screen installation and tensioning as well as on routine general maintenance.
7.5.12 When using shaker screens that need tensioning, check tension 15 mm to 30 mm after installation and hourly thereafter.
7.6 Design of degassers
7.6.1 The degasser shall draw suction from the compartment immediately downstream from the sand trap.
7.6.2 When the sand trap is in use, flow to the degasser compartment shall be over a long, high weir.
7.6.3 While the degasser is in use, there shall be no tank bottom equalization between the degasser compartment and those adjacent to it.
7.6.4 Degas fluid before it reaches the pumps feeding the downstream equipment.
7.6.5 The pump used to power the jet on vacuum degassers shall take suction from the same compartment into which the vacuum degasser discharges.
7.6.6 Position the degasser suction 30 cm (12 in) above the tank bottom.

7.6.7 Agitate the degasser compartment well.
7.6.8 The centrifugal pump feeding the eductor jet of vacuum degassers shall provide the feed head recommended by the manufacturer. Install a pressure gauge to permit the head to be verified.
7.6.9 The degasser capacity shall be at least equal to the planned circulation rate in all of the hole intervals in which gas intrusion is considered to be a hazard.
7.7 Operation of degassers
7.7.1 Operate degassers to receive all drilling fluid from the lowest portion of the borehole (“bottoms”) after trips. Crews should be familiar with start-up procedures and provide regular checks to confirm that the equipment is working properly.
7.7.2 Calculate the volume fraction (percent) gas or air in a drilling fluid by dividing the difference between pressurized drilling fluid density and unpressurized drilling fluid density by the pressurized drilling fluid density, and multiplying this fraction by 100. The calculation can be expanded to include the possibility of dissolved gas by subtracting from 100 % the mass of unpressurized drilling fluid divided by the mass of the same volume of degassed drilling fluid, expressed as a percentage.