DESIGN OF GAS HANDLING
FACILITIES FOR SHALE OIL
PRODUCTION
Rocky Mountain Gas Processors Association – 2015
Regional Conference
Thursday November 19, 2015 Denver, CO
Mike Conder and April Schroer
Overview
Trends in Gas Handling from Shale Oil Production
Designing with PVT Fluid Analyses
Simulating Gas Handling at Oil Production Facilities
Using GOR Data
Modeling Different Oils
Lift Gas Design & Sources
VRT Design & VRT/VRU System Value
Practical Tips for Facility Design
Trends in Gas Handling from Shale Oil Production
Single well pads transition to multi-well pad productionLow volume vertical wells to high volume horizontal wells
Change in Size & Complexity
Increase air emission requirements
Pushing threshold limits – esp. VOCs
Oil Price Boom to Slump MentalityBoom
Projects schedule driven
Projects not necessary based on long term economics
Little published on “more” complex designs and operation
Slump
Projects transitioning to “Cost” driven
“Critical” economic project drivers
Use “slump time” to improve facility designs
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Transitioning from a
“Standardized Design”
to a
“Design in Progress”
Designs for Shale Oil/Gas Handling – “Traditional”
“Traditional” Well Pad typical flow sheet
4
Designs for Shale Oil/Gas Handling “4 Well Multi”4 –Well Multi-Well Pad Flow Sheet
5
GATHERING
Designing with PVT Fluid Analyses
PVT (Pressure-Volume-Temperature) fluid properties analysisMainly used for planning field exploitation by reservoir engineers
However, facilities engineers can use this information for equipment design
Predict gas handling requirements of the well and/or field
PVT samples are typically taken at surface separator Gas/Oil/Water samples taken & then recombined in the lab
GC results are carbon number (CN or “alkane – straight chain”) analysis
Typical range from C1 (methane ) to C36 with inerts
CN can be used in a process simulator for equipment sizing
Our work is based on VMG Sim “PIONA” (Paraffin's, Iso-paraffins,
Olefins, Naphthenes and Aromatics) new oil characterization Gives improved liquid property results
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Simulating Gas Handling at Oil Production Facilities
Oil characterization by PIONA vs straight chain CN data
Little difference in gas production & analysis between two cases
Credible difference in oil properties
Need best oil properties for stabilization designs & meeting transport specs
Off gas flow from a stabilizer will impact facility & gas/handling design
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Table 1CN (Alkane) Simulation PIONA Simulation
Process Simulation
ComparisonsHigh Press
Separator
Low Press
Separator
Recovered Tank
Flash
High Press
Separator
Low Press
Separator Recovered Tank Flash
OIL DATA Oil Production Oil Production
Oil Make, BPD, @ STD 609.1 463.1 454.8 596.3 451.3 443.0
API Grav @ STD 47.39 57.40 56.47 35.06 51.86 50.86
GAS DATA Gas Production Gas Production
Flow, MSCFD 512 36.1 11.6 517 34.3 11.6
Separator Gas SG 0.812 1.356 1.777 0.814 1.369 1.756
Heating value, BTU/SCF 1,350.0f 2,125.0 2,853.0 1,352.4 2,161.6 2,866.4
Total Heating value, BTU/SCF 1,431.1 1,432.9
Well Gas/Oil Ratio (GOR) 1,230.7 1,270.7
512 517
56.5 50.9
Using GOR Data
Reservoir engineers can provide gas-oil ratio (GOR) and type
curve (time vs. production)
Useful design tool for facilities engineer BUT “use with caution”
Normally developed from similar wells in the area (analogue wells)
GOR data can be misleading
GOR usually calculated from actual production data
Rarely adjusted for vapor recovery volumes
Measured separator oil density lower than final produced oil density
Make sure know how GOR is calculated
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Using GOR Data (continued)
Design impacts
Well operating conditions strongly influence GOR calculations
Differences can range ± 25-50%
These differences can impact the equipment design
(stabilization)
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Table 2 Alkane (CN) Simulation PIONA Simulation
Calculated GOR ValuesHigh Press
Separator
Low Press
Separator
Recovered Tank
Flash
High Press
Separator
Low Press
Separator
Recovered Tank
Flash
OIL DATA Oil Production Oil Production
Oil Make, BPD, @ T,P 617.7 477.0 467.8 601.5 461.6 452.6
Oil Make, BPD, @ STD 609.1 463.1 454.8 596.3 451.3 443.0
GAS DATA Gas Production Gas Production
Flow, MSCFD 512 36.1 11.6 517 34.3 11.6
GOR @ T,P 829 1,149 1,196 860 1,194 1,244
GOR @ STD 841 1,184 1,231 867 1,222 1,271841 1,184 867
46%
1,231 1,222 1,271
47%
Modeling Different Oils – Unit Based
3 typical oils (lt, med, hvy) modeled using PVT @ same
operating conditions
PVT reported API Gravities:
Oil B was used in the previous calculations
Table 3 Oil Production Gas Production, MSCFD
Process
Simulation for
Different OilsActual
BPD Standard BPD API Grav. RPV
From HP
Separator
From LP
Separator
From
VRT
Total Gas
Production
C2+ GPM Total
Gas
ECD Gas
Burned
Oil A 470.1 458.9 63.29 8.08 7,099.8 27.4 16.3 7,143.5 6.50 3.9
Oil B 467.9 458.9 41.53 7.05 548.7 22.9 14.3 585.8 9.08 2.4
Oil C 467.2 458.9 41.26 7.45 843.0 20.5 14.9 878.4 9.98 2.5
549
1193%
7,100
843
37.2
43.7
35.4
17 %
Oil A: 61.3; Oil B: 49.6; Oil C:35.8
Modeling Different Oils – (continued)
HPS production ranges +/- 1200%
Total LPS & VRT flash gas production only ranges +/- 25%
LPS/flash gas handling equipment sizing strongly dependent on total oil production
Less dependent on GOR
Simplifies design of gas handling facilitiesEquipment size based on oil production rates
The flash gas historically burnedState regulations require capturing flash gas for VOC control
Recent North Dakota regulations now require capturing most flash gas volumes
Modeling Different Oils – (continued)
Value of LPS & VRT flash gas not significant for single well
facilities, but very significant for multi-well pads
3-6% of total produced gas volume
10-14% of total gas revenue of the well
Adds ±$1/bbl. of the oil to the total wells revenue (Q1 Rocky Mtn. prices)
Table 4 Gas Production NGL Recovered
Btu Quantities & $/BBL
Values – flash gas 75 psig
basisHPS Gas,
MMBTU/D
LP Flash
MMBTU/D
VRT Gas
MMBTU/D
HPS Gas, NGL
GPD
LP Flash NGL
GPD VRT Gas NGL GPD
Case 1 - Light Oil 5,721.4 12.7 2.9 17,207 4 3
Case 2 – Med. Oil 717.3 15.3 3.4 1,125.0 164.6 184.9
Case 3 - Heavy Oil 36.5 1.2 0.8 2,501.6 184.8 226.9
Total Value, $/day Percent of Total Value
Case 1 - Light Oil 37,232 48 13 99.8% 0.1% 0.0%
Case 2 – Med.Oil 3,635 218 197 89.8% 5.4% 4.9%
Case 3 - Heavy Oil 2,629 189 230 86.3% 6.2% 7.5%
Total Value, $/BBL Oil Produced
Case 1 - Light Oil 81.13 0.10 0.03
Case 2 – Med.Oil 7.92 0.48 0.43
Case 3 - Heavy Oil 5.73 0.41 0.50
$0.91
$0.13
$0.91
Modeling Different Oils – Single Well (continued)
HPS operating pressure affects LPS & VRT flash gas volumes
Volume and total BTU production increases with HPS pressure
75 psig HPS pressure : flash gas 5% of total flow and 8% BTU value
250 psig HPS pressure : flash gas 16% of total flow and 25% BTU value
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0%
5%
10%
15%
20%
25%
30%
35%
40%
50 100 150 200 250 300 350 400
HPS Pressure, PSIG
Flash Gas % of Total Flow
Flash Gas % of Total MMBTU/day
8%
5%
25%
16%
Lift Gas Design
Most shale oil wells need artificial lift to produce the wells
Gas lift is a common method of artificial lift
High pressure gas stream is injected into well bottom
Assists in driving produced water/oil to the surface
Single Well Site Iift gas compression
Plus: uses HPS gas compressed by pad compressors
Plus: easy installation; minimal facilities investment
Minus: requires many temporary units, one on each site
Minus: high $/hp for small units
Minus: no back-up for downtime
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Lift Gas Design (continued)
Centralized lift gas compressionPlus: permanent gas lift compression facilities
Plus: lower $/HP
Plus: back-up for downtime
Plus: simple to add new wells; extend pipe
Minus: requires installation of gas lift lines & larger gathering systems
Minus: potential liquid drop problems in pipe and at well pads
Dew point units can be installed to prevent liquid problems Removing gas liquids increases net gas production from wells
Dry lift gas strips light ends from the oil
Helps stabilize the oil
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Vapor Recovery Tower (VRT)
VRT introduced into well pad designs 2012/13
Provides a positive suction pressure to VRUs
Act as a liquid seal to prevent air ingress (O2) into the flash gas
Previously connected VRUs to tanks directly to tanks
<1 psig inlet pressure, create vacuum and pulls air into the flash
gas
Result O2> 10 ppm exceeding pipeline and facilities specs
Downstream operators installing O2 meters and will
shutdown on high O2
Increase risk of corrosion and solids with H2S present
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Vapor Recovery Tower (VRT) - Continued
Vertical Vessel
• 30” to 60” dia. x 30’-40’ tall
• Internal dip tube
• Oil enters top
• Flows to bottom
• Fills vessel
• Pressure pushes oil up the dip tube to oil tanks
• Flash gas leaves top to VRU
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OIL TANK
Flash Gas to VRU
Oil
VRT Design Continued
Original VRU design Approximately 5 feet above oil tanks
Problem upset downstream equipment (VRU)Blow out seal and limited pressure control (<2 psig pressure)
VRT design optimizationSnap acting dump valves upset downstream equipment operation (VRU/ VRT liquid levels)
Install a large K/O drum on the VRU
Increase the overall height of the VRT10 feet above tanks and some up to 20 feet above tanks
Convert to throttling dump valves
Install PCV to vent or flare on the VRU to avoid blowing VRT seals
Operate VRT at 2-4 psig for good control, prevent air ingress
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VRT/VRU System Value – Not Always Economic
ASSUMPTIONS- $225k installation cost
- $2,500/mo. VRU lease
- 450 BPD IP Rate
- 35 psi secondary separator pressure
- $ 0.41/BBL gross value of VRT flash gas
- 85/85 POP gathering & processing fee
- Value is sensitive to HP and LP flash pressures
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- Value is sensitive to HP and LP flash pressures
Tips on Shale Oil Gas Handling Facility Design
Heavy gas condenses, can build large recycleMaintain higher temps from VRU coolers with temperature controller
Use HPS gas for compressor recycle; helps clear out heavy gas
Air ingress can bust oxygen specificationUse HPS gas for VRU recycle, keep VRU running (no on/off operation)
NEVER use VRU’s to pull vapors from storage tanks
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Tips on Shale Oil Gas Handling Facility Design
(continued)
ECD capacity VRT/VRU’s capture 90-95% of flash gas
ECD’s sized to handle low volume, also full VRU/VRT volume when VRU down
Design for flexibility Peak vs decline operation
Strategic drilling (offset) to optimize facility sizing and cost
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Closing & Questions
Overall there are many opportunities available to better design and operate gas handling equipment.
During this low-price oil environment, it is critical to use this time and available resources to minimize the capital cost of these production facilities and improve the economics of the well.
Questions ???
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