Design Tips 2

Separators/ Vessels

• Oil & Gas Separation Stages: More stages, more oil recovery. Liquid hydrocarbon are more valuable than gas. 2X. Stage pressure ratios are 3-4 as in compressor to which gases go. Usually 2 - Medium Pressure (MP) and Low Pressure (LP). For High Pressure (HP) fluids, earlier 3 and now 2. Decide by pressure decline observed in nearby fields. LP stage ≈ 1 to 2 bar (Storage tank height + Level Control Valve, 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 Pressure Alaram High (PAHH), 10% for Pressure Alarm High (PAH) and 5% for Normal Operating Pressure (NOP) ≈ 12

• Slug Catchers: 2 types - (1) Gas Knockout Drum (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 calculation. Note: Let suppliers size the fingers to optimize 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. 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 avoids a blocked inlet scenario. Single LCV throttling tends to starve or fluctuate downstream equipment/ compressor feed and results in a blocked outlet

• 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 who calls out “Don’t wreck the expensive compressor with cheap scrubbers or with inadequate engineering”

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

• Residence Time: 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 oil/ water droplet to rise/ fall. Decides water/ oil carry over, ppm. See ‘3Phase Separator’ in Sizing. 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 Electrostatic Separator (ESP)

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

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

• Condensate Stabilizers: Water accumulation on top trays. Dewater or decant. See 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 RV, a minimum 7% margin over MOP

• Vessels in series DP: Poor design to keep reducing DP based on reducing NOP. i.e., DP = 16 for first; 14 for second and 12 bar for third. Will call for full flow RV in all. Keep DPs same

• DP: Check and increase DP of LP vessel subject to gas blowby if it bloats up LP flare size. LP DP = HP source PAHH/1.3. Or route gas blowby load to HP Flare, as it is unlikely additive load

• Train Isolation: Avoid many isolation + DBB valves for each equipment. Go for DBBs at inlet and outlet of 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. See Safety Alerts. Many bends <10D downstream of an LCV/ PCV have failed due to erosion corrosion

• Inlet Separator: Pressure floats on downstream compressor suction pressure. Delete vapor outlet Pressure Control Valve (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 provided unaware of compressor’s pressure control capability. PCV deletion leads to lower backpressure on wells and higher recovery; 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 can 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 on a bigger PCV leading to RV chatter, rupture and explosion. Bigger PCVs cause suction pressure fluctuations in downstream compressor

• Flare PCV as Blow Down Valve (BDV): PCVs are Fail Open (FO) but are not a substitute for BDV that is opened on fire via Safety Instrumented System (SIS) on Fire & Gas (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 downstream compressor suction pressure, say 1 bar. Test Sep pressure floats smoothly and gives constant ∆P for oil/ water LCVs to keep level steady without hunting. PCV leads to LCV hunting as downstream pressure varies

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

• Test Sep: Well cleaning or gas well dewatering fluids are 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

• 2 Phase Sep: If required, check for future 3-phase separation to take bulk water out as water cut increases. Provide support channels for future internal weir

• Sizing: Separator sized for 100,000 Barrels Liquid Per Day (BLPD) with 10 to 90% water cut ends up sized on 90,000 Barrels Water Per Day (BWPD) + 90,000 Barrels Oil Per Day (BOPD). Second or oil draw off compartment is usually 1m long. A variable height weir can reduce overall size. Initially low weir with a thicker oil layer. Later increase weir height as water cut increase for thinner oil layer. Provide support channels for weir height increase. Or size on 90% water cut and vary LAL/NLL/LAH in initial years