Casing Gas Compression Compact Compression Inc. Calgary, Alberta, Canada

Casing Gas •  Oil in forma:ons includes natural gas in solu:on •  For oil to flow into a well, the pressure at the bo@om of the well must be less than that of the forma:on. As oil flows into the well, gas will come out of solu:on and collect in the casing •  This gas was tradi:onally dealt with in one of two ways –  Ven:ng the casing to atmosphere –  Connec:ng the casing to the flow line

Casing Pressure Vent to atmosphere Connect to flow line •  Ven:ng methane to •  Can reduce well atmosphere is bad for the performance due to high environment, methane has backpressure on forma:on 25x the greenhouse effect •  Convenient, only 1 pipeline of CO2 (based on 100 year required, gas can be global warming poten:al) separated from stream and •  Was:ng a poten:ally used at ba@ery valuable and finite resource •  This prac:ce is now illegal in many countries for the above reasons

Well connec:on diagram

Why Casing Gas Compression? •  No ven:ng –deliver gas to flow line •  Can use gas as fuel or sell it •  Reduce casing pressure, lowering the backpressure on the forma:on. This will: –  Increase rate of oil produc:on –  Increase overall oil recovery



Typical Site Layout

What does it do •  Reduce pressure in casing, lowering bo@om hole pressure •  Differen:al pressure between the forma:on and bo@om hole is what drives the inflow of oil to the well •  Maximum flow line pressures can reach between 1380-2070 kPa / 200-300 psi •  A compressor can typically reduce casing pressure to 35-207 kPa / 5-30 psi, depending on size and gas flow •  Reduc:on of backpressure against the forma:on results in higher oil recovery rate •  This effect will be more significant on low pressure forma:ons

–  Forma:on pressure of 20700 kPa (3000 psi), well is 1380 kPa (200 psi), drops to 207 kPa (30 psi), change is 6% –  Forma:on pressure is 6894 kPa (1000 psi), well is 1380 kPa (200 psi), drops to 207 kPa (30 psi), change is 18%

IPR Curves •  Inflow Performance Rela:onship •  Indicate change in inflow rates with change of bo@om hole pressure •  Essen:ally, the reservoir’s ability to flow to the well at a range of bo@om hole pressures •  Depends on reservoir structure, permeability, pressure, and other factors •  Can be used as a first indicator of a well poten:ally suited for casing gas compression

Example IPR curve

Suitability of a well for casing gas compression

Wells Prone to Gas Lock •  Gas lock may occur due to a variety of condi:ons, such as high GOR, pump spacing, and pump landing loca:on •  A gas locked pump can cause severe equipment damage •  On wells where this is a known issue, a casing gas compressor may aggravate the problem, as lowering downhole pressure will increase the rate of gas breakout •  Poten:al solu:ons would be: –  –  –  – 

Resefng pump spacing to maximize pump compression ra:o Adding a gas anchor or other gas separa:on device to the pump Change to a pump designed to handle gas Re-landing the pump further below the perfora:ons

•  If these do not solve the problem, this well may not be suitable for casing gas compression •  The solu:on may be to increase head pressure on the pump. This would involve maintaining greater fluid height in the well. Essen:ally, giving up some amount of produc:on rate in order to avoid gas lock issues. •  Tes:ng is cri:cal, the only way to ensure that a well is suitable for casing gas compression is to test in advance

Tes:ng for suitability •  Trailer mounted compressors are simple to move around, saving labor and :me over tes:ng with a skid mounted unit •  Screw compressors are quite flexible in performance can be adapted to a wide range of opera:ng condi:ons •  Gas driven, will run off compressed gas, no need for an electrician to hook up power •  A test compressor will determine exactly how a well will respond to casing gas compression, making the economics of the applica:on a certainty rather than specula:on •  Can be equipped with a flow meter to precisely determine required size of compressor

How do we do it •  Variety of compression elements, chosen based on opera:ng condi:ons –  Hydraulic Reciproca:ng •  Low flow (0.1-2 e3m3/day or 0.3-70 mcfd) •  High pressure (up to 3450 kPa / 500 psi)

–  Small Frame Reciproca:ng •  Medium flow (0.5-6 e3m3/day or 17-200 mscfd) •  High pressure (up to 2750 kPa / 400 psi)

–  Screw •  High flow (6-37 e3m3/day or 200-1300 mscfd) •  Medium pressure (up to 2070 kPa / 300 psi)



Hydraulic Casing Gas Compressor •  •  •  •  • 

Purpose design for low volume casing gas applica:ons Ideal for single well applica:on Compressor is designed for sweet or sour service No operator setup or adjustment is required Eliminates issues common with conven:onal casing gas compressors – 

No process valves or coolers to become contaminated •  •  • 

– 

No liquid handling system (compressor can pump liquid or gas) •  •  •  • 

•  •  •  •  •  • 

No inlet valve No recycle valve No intercooler No separator No level shutoff No level switch No liquid pump

Ultra reliable gear pump and electric motor power supply Minimum moving parts Satellite call out system no:fies operators if unit shuts down No external leak points for oil or gas seals Automa:c restart if grid power is lost Capacity control –  – 

Compressor will adjust cycle rate to match flow Up to 100% turn down

HCG Performance (US units) HC613 Compressor with HPP-13E Power pack Maximum ΔP: 225 psi

SUCTION PRESSURE

DISCHARGE PRESSURE



75

100

125

150

175

200

225

250

275

5 10 15 20 30 40 50

38 49 61 72 95 118 140

37 48 59 70 93 116 139

35 47 58 69 91 114 137

34 45 56 68 90 112 135

33 44 55 66 88 111 133

32 43 54 65 87 109 132

31 42 53 64 86 108 130

84 106 129

127

HC616 Compressor with HPP-13E Power pack Maximum ΔP: 350 psi

SUCTION PRESSURE

DISCHARGE PRESSURE



200

225

250

275

300

325

350

375

400

5 10 15 20 30 40 50

20 27 34 41 55 70 84

19 26 33 40 54 69 83

19 26 32 39 54 68 82

18 25 32 39 53 67 81

17 24 31 38 52 66 80

16 23 30 37 51 65 79

16 23 29 36 50 64 78

49 63 77

76

*Projected Performance based on 2500 k, gas density .665, temp 68 ºF Pressures in PSI Flow Rates in MSCFD

HCG Performance (metric) HC613 Compressor with HPP-13E Power pack Maximum ΔP: 1550 kPa

SUCTION PRESSURE

DISCHARGE PRESSURE

35 70 100 140 200 275 345

510 1.1 1.4 1.7 2.1 2.7 3.4 4.0

690 1.1 1.4 1.7 2.0 2.7 3.3 4.0

860 1.0 1.3 1.7 2.0 2.6 3.3 3.9

1035 1.0 1.3 1.6 1.9 2.6 3.2 3.9

1200 0.9 1.3 1.6 1.9 2.5 3.2 3.8

1380 0.9 1.2 1.5 1.9 2.5 3.1 3.8

1550 0.9 1.2 1.5 1.8 2.5 3.1 3.7

1720 2.4 3.0 3.7

1900 3.6

2400 0.5 0.7 0.9 1.1 1.5 1.9 2.3

2585 0.5 0.7 0.9 1.1 1.5 1.9 2.3

2760 0.5 0.7 0.8 1.0 1.4 1.8 2.2

HC616 Compressor with HPP-13E Power pack Maximum ΔP: 2400 kPa

SUCTION PRESSURE

DISCHARGE PRESSURE

35 70 100 140 200 275 345

1380 0.6 0.8 1.0 1.2 1.6 2.0 2.5

1550 0.6 0.8 1.0 1.2 1.6 2.0 2.4

1720 0.6 0.8 1.0 1.2 1.6 2.0 2.4

1900 0.5 0.7 0.9 1.1 1.5 2.0 2.4

2070 0.5 0.7 0.9 1.1 1.5 1.9 2.3

2240 0.5 0.7 0.9 1.1 1.5 1.9 2.3

*Projected Performance based on 760m, gas density .665, temp 20 ºC Pressures in kPa Flow Rates in 1000 m3/day

Typical process diagram

Shutdowns and warnings •  The PLC manages all aspects of compressor opera:on. It will provide the following alarms: –  –  –  –  –  – 

Low suc:on pressure High discharge pressure High discharge temperature High oil temperature Low oil level Capacity loss

•  As well as shutdowns for these condi:ons: –  –  –  – 

Oil level low Oil leak detected Motor overload Failure to cycle

•  Compressor will send a message via satellite to indicate an alarm or shutdown condi:on

CG25 Sweet - Standard CCI Compressor Package

Compact Compression Inc. CG 25 Quincy QRNG 370 2 Stage Sweet DISCHARGE PRESSURE

Suction

2 stage reciproca:ng 25 hp electric 0-205 kPa / 0-30 psi inlet 690-2760 kPa / 100-400 psi discharge •  Op:onal Inlet scrubber and autodrain pump •  Sweet natural gas •  •  •  • 

5 10 20 30

150 85 108 155

200 83 106 153 199

250 81 104 151 197

300 79 102 149 195

350 77 100 147 193

*Performance based on Sea Level, gas density .65, temp 68 ºF Pressures in PSI Flow Rates in MSCFD High Efficiency Intercooler required for flows in grey

Typical process diagram

Reciproca:ng compressor •  •  •  • 

Suc:on pressure from 0-205 kPa (0-30 psi) Discharge pressure from 690-2760 kPa (100-400 psi) Flows up to 5.5 e3m3/day (200 mscfd) Sour compa:ble compressors available

Inlet regulator •  When well is shut in, casing pressure will increase to shut-in pressure (can be 2060 kPa / 300+ psi) •  Compressor cannot process gas above 206 kPa / 30 psi •  Inlet regulator reduces incoming gas pressure to a tolerable level for the compressor

Low Pressure Recycle Regulator •  Compressor speed can never be perfectly matched to gas flow •  Recycle regulator provides simple and effec:ve capacity control, up to 100% turn down (no flow into compressor) •  Maintains specified minimum pressure on casing (35-70 kPa / 5-10 psi)

Shutdown Switches •  Suc:on pressure low

–  If recycle regulator fails, compressor will pull vacuum, so it will be shutdown at specified low pressure on inlet

•  Discharge pressure high

–  If compressor discharge is blocked, it will shut down at specified pressure to protect internal components

•  Discharge temperature high

–  Compressor valves suscep:ble to damage from overhea:ng. Compressor will shutdown before temperatures that may damage valves are reached

•  Compressor oil pressure low

–  If compressor oil pressure is low, compressor will shutdown to avoid running without lubrica:on

Inlet Scrubber •  Removes liquids that have condensed out of the gas stream coming in to the compressor •  Protects the compressor from possible liquid slugs due to depressions or traps in the plumbing •  Not always necessary – In hot climates there may be very li@le condensa:on in the line, and if there are no liquid traps there will be no buildup of slugs •  The casing does most of the job of removing liquids entrained in the gas stream

Example of liquid trap

Autodrain Pump •  Removes opera:onal requirement of daily draining of inlet scrubber, simplifies disposal of condensate •  Pneuma:c or electric driven •  Pumps liquids out of scrubber and into discharge, will be carried into flowline with gas discharge

Intercooler •  Cooling is required between stages of a mul:stage compressor •  Cooling is cri:cal to maintain acceptable cylinder temperatures in second stage •  High performance intercooler recommended for hot climates and high pressure ra:os

Aker Cooler •  Cools gas before it leaves the compressor •  Only required if there are concerns with elevated temperatures at the surface - 176°C (350°F) max •  High temp of gas discharge will otherwise be absorbed by the oil of the flow line –  2 e3m3 of natural gas @ 176°C (350°F) flowing into 400 bbl/day of 30°C (86°F) crude oil, will raise the temperature by 0.37°C (0.67°F)

Shutdown Interlock •  When compressor shuts down casing pressure will rise •  This leads to a drop off in inflow to the well •  It is possible that while the compressor is shut off the pumpjack could pump itself off, damaging equipment •  Using an interlock so that both compressor and pumpjack shut off together will prevent this •  On certain wells this may not be needed, a simple auto bypass may be sufficient to maintain produc:on un:l the compressor can be restarted