Design Tips 2

Separators/ Vessels

• Oil & Gas Separation Stages: More stages, more oil recovery. Liquid HC more valuable than gas. Stage pressure ratios 3-4 as in compressor to which gases go. Usually 2 - MP and LP. For HP fluids, earlier 3 and now 2. Decide by pressure decline in nearby fields. LP stage ≈ 1 to 2 bar (Storage tank height + LCV ΔP). MP = 3-6 bar. First or Inlet Sep 9-12 (24) bar. Design pressure to suit flange rating. 150# ~ 17 bar. Deduct 10% for PAHH, 10% for PAH and 5% for NOP ≈ 12

• Slug Catchers: 2 types - (1) Gas KOD on top of 1-2 liquid barrels. Liquid barrel: Single - co-axial. Multiple - transverse (2) Finger type for bigger liquid loads. 4 - 10 gas fingers with matching liquid fingers below. Gas: 1,000μ liquid separation, as there is a downstream separator. Liquid: Hold-up volume. 2 phase gas-liquid separation. Simple 4 lines calc. Note: Let suppliers size the fingers as there is a good optimization on diameter vs available plate wall thickness to cut costs of forged components

• Inlet Slug Control: (1) Inlet LCV throttling or (2) pinching inlet V bore ball valves - after pig receiver T. Longer pipelines surge more. DCS table to pinch longer pipelines first, one at a time, in sequence, based on level rise in separator. For reasons unknown, even a mild pinching drastically dampens surging. Better than LCV as throttling multiple valves avoid blocked inlet scenario. LCV option tends to starve or fluctuate downstream equipment/ compressor feed

• KODs: (1) No internals: Gravity settling. Stoke's or Intermediate law. (2) Internals: K Factor based on internal type. Do NOT reduce KOD size based on supplier promises. Many compressors are affected by undersized suction scrubbers and poor suction piping layout that accumulates liquid, leading to liquid carry over to compressors - with great cost to performance and lost production. Google “Design of Compressor Suction Scrubbers”, Noijen Clinton - Shell. He calls out “Don’t wreck the expensive compressor with cheap scrubbers or with inadequate engineering”

• Sizing: Process calcs are preliminary. Do not provide to Owner. Give sizing calcs from supplier. Fees received Vs performance risk to an engg company

• Oil:Water Droplet Sizes: 0.5 minutes between an alarm and trip (LALL/LAL/NLL/LAH/LAHH). Residence time at NLL 3-5 minutes. Water: NLL - depth thru which an oil droplet at bottom rises to oil layer. Oil: NLL - similar, for a water droplet to fall to water layer. Time taken from entry to weir is time available for oi/water droplet to rise/fall. Decides water/ oil carry over, ppm. See ‘3Phase Separator’ in Sizing. Play and observe to learn more. Usually, 150-200 μ is desired - zero emulsion assumed

• Typical Spec when there is no emulsion: Liquid carry over 0.1-1 gal/MMSCFD; Water in Oil 0.5 to 5%. Oil in Water 500 to 2,000 ppm. As water viscosity is low, oil droplets separate well; Oil in water is low

• Emulsion: Field specific. Minor to severe. One can develop a correlation to predict oil/ water carry over based on droplet sizes calculated. If emulsion is high, heat it before separation. Coalescer packs in liquid layer help but get plugged in service by sand and debris in well fluids. Go for ESP - Electrostatic Separator

• Horizontal KOD Split Flow: Earlier designs had split flow - 1 inlet with 2 outlets to halve vapor flow and reduce diameter. Based on liquid droplet settling time, vessel length will go up. Liquid hold-up usually governs. Split flow design no longer common

• Higher than planned loads: Pre-flash or Gas Sep to reduce gas load; Inline Sep to reduce liquid load

• Condensate Stabilizers: Water loading on top trays. Dewatering or decanting to take water out as in standard textbooks

• Design Pressure (DP): 5% variations in Normal Operating Pressure (NOP), 10% for PAH, 10% for PAHH. Based on 5-7% blowdown for a conventional PSV, a min 7% margin over MOP

• DP: Vessels in series, poor design to reduce DP based on margin over OP. i.e., DP = 16 for first; 14 for second and 12 bar for third. Full flow PSV in all. Keep DPs same

• Design Pressure (DP): Check and increase DP of LP vessel subject to gas blowby if it bloats up LP flare size. LP DP = HP PAHH/1.3. Or route gas blowby load to HP Flare

• Isolation: Avoid many isolation + DBB valves. Go for DBBs at inlet and outlet for spared trains and individual flow lines. Provide single isolation valve within a train, to minimize purging. Review start-up sequence and provide pressure equalization valves

• P&ID Note: “No valve or expansion/contraction/ bends within 10D”, to allow smooth separation

• Inlet Separator: Pressure floats on downstream compressor suction pressure. Delete vapor outlet PCV to compressor. PCV (1) Potential blocked outlet and (2) Starves/ fluctuates compressor feed. It’s opening-closing chatter leads to continuous disturbances to smooth compressor operation. PCVs were in earlier designs unaware of compressor’s pressure control capability. PCV deletion leads to lower backpressure on wells and hence higher recovery or allow higher suction pressure and more throughput

• Flare PCV: Dumps Associated Gas to continue oil production till compressor is fixed. Avoided to avoid greenhouse gases. Don’t size for full flow. Dynamic simulation to select right size (40-60%) set at PAH. Smaller PCVs provide better control and response. Ramp it fast in DCS to 60% or use a quick-opening characteristic valve. Reduces flare load. See Safety Alert - Bigger sluggish PCV led to PSV chattering, rupture and explosion. Bigger PCVs cause suction pressure fluctuations in downstream compressor

• Flare PCV as BDV: PCVs are Fail Open (FO) but are not a substitute for BDV that is opened on fire via SIS on F&G to bring down vessel pressure fast. PCVs tend to hold the pressure. A solenoid on PCV to open on fire is a bad old practice - mixing control (DCS) and protection (SIS) layers. PCV load is more vis-à-vis smaller BDV load to flare

• Test Sep: Change outlet PCV to dPCV with a ∆P over compressor suction pressure, say 1 bar. Test Sep pressure floats smoothly and gives constant ∆P for oil/water LCV to keep level steady without hunting

• Test Sep: An intermittent service. No spare PSV. Minimize DBB

• Test Sep: Well cleaning or gas well dewatering fluids routed to it. Find all modes of operation to avoid late changes. Review impact of solids (proppants/ sand) on Test Sep LCV outlet. See Safety Alert

• Test Sep: May operate with LP or declining wells at pressures lower than compressor suction. Finalize LP gas routing options early