design of a co2 injection system for sequestration and...

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Design of a CO2 Injection System for Sequestration and Enhanced Oil and

Gas Recovery Testing

By: Ray McKaskle – Trimeric CorporationCo-Authors: Kevin Fisher – Trimeric Corporation

Scott Frailey – Illinois State Geological Survey

Fifth Annual Conference on Carbon Capture & SequestrationAlexandria, Virginia

May 8-11, 2006

TRIMERIC CORPORATION

2 TRIMERIC CORPORATION

Project Objectives

• Design and build CO2 injection system to support sequestration and enhanced oil and gas recovery testing at multiple sites in the Illinois Basin– Coal Bed Methane– Huff and Puff– Well Conversion– New Well / Pattern Flood– Deep Saline Reservoir

• Specify and obtain other required equipment– CO2 Storage Tank– Line Heater

• Address safety concerns for liquid CO2 service• Predict pressures and phases in injection wellbore


Design Objectives

• Equipment must be portable and suitable for oil field use• System must have flexibility to deliver CO2 over a wide

range of conditions:– 15 Mscf/d (0.9 ton/day) CO2 vapor for Huff and Puff test– 2.2 MMscf/d (129 ton/day) CO2 liquid for Deep Saline Reservoir test

• CO2 Storage– Maximum capacity required for test flexibility– Portable storage tank needed to minimize transportation and site

support costs• Line Heater

– Must vaporize some or all of CO2 for tests that require vapor injection– Must heat CO2 up to near ambient temperature for realistic simulation

of future CO2 injection projects


Equipment Overview

• Pump Skid– 3, single piston cylinder pumps in parallel, 7 gpm (69 lb/min)

capacity each– Pressure regulated bypass valves for constant pressure

injection– Return line with globe valve for constant flow rate injection

over a wide range of flow rates– Liquid flow meter with flow transmitter and totalizer

• CO2 Storage Tank– 60 ton capacity– Portable tank to reduce transportation and site support costs

• Line Heater– Propane fired, 250 MBtu/hr capacity– Suitable for water or glycol service– Skid and lift lugs added for increased portability


Safety Design Considerations for Liquid CO2 Service

• Liquid CO2 will be at 0 oF and range from 300 psia to 1,000 psia in the pump skid piping

• If liquid CO2 becomes trapped in the lines, it will heat rapidly and pressure will rise– System is designed with automatic pressure relief valves

located every place that liquid CO2 has the potential to be blocked in

– PRV discharges will be routed to divert flow of cold vapor CO2that would exit the PRV’s in order to reduce the risk of personnel exposure

• Normal shutdown procedures will vent liquid CO2 from bottom of pipes to prevent equipment exposure to temperatures lower than design conditions

• Ambient CO2 monitors will be installed at four site locations and will alarm if elevated levels of ambient CO2 are detected


Pump Skid Process Flow Diagram

TI 100 TSH 110

VLV103

VENT

PI 110

FQI 110

2" SCH. 80

2" TO 1"

REDUCER

1" SCH. 80

1" SCH. 80

PMP101

PMP102

PMP103

1" SCH. 80

FE 110

½” CONNECTION

FOR TUBING FOR

VAPOR

PRESSURIZATION

LIQUID SUPPLY LINE

FROM CO2 STORAGE

LIQUID RETURN LINE

TO CO2 STORAGE

LIQUID DISCHARGE LINE

1" TO 2"

EXPANDER

PSL 100

PI 100

24" RISER

TI 110

100 MESH

STRAINER

PRV101

450 PSI

PRV102

WITH 12" RISER

PRGV101

HAND

OPERATED

PRESSURE

REGULATING

VALVE

PRV105

¾” T/L

CONNECTION

¾” T/L

CONNECTION

VLV108

VENT

VLV109

VENT

VLV110

VENT

VLV115

VENT

VLV119

VENT

PRV107

450 PSI

24" RISER

12" RISER

PRV103

WITH 12"

RISER

PRV104

WITH 12"

RISER

PRV106

WITH 12"

RISER

VLV101 VLV102

STR101

VLV121

VLV122

VLV104

VLV105

VLV106

VLV107

MTR101

MTR102

MTR103

PRGV102

PRGV103

VLV111

VLV112

VLV113

VLV123

VLV124

VLV114VLV116

TO LINE

HEATER

VLV117

VLV118VLV120

24" RISER

WITH CAP


Overall Process Flow Diagram

In

jectio

n

TSL 115

TI

120

LINE HEATER

CO2 STORAGE WELLHEAD

VENT

1" SCH. 80 NOT INSULATED

FE

120

FQI

120

PISTON PUMP SKID

(SEE OTHER DRAWING)

PSL 120

PI 120

½” TUBING WILL BE

ATTACHED TO THIS

VALVE AND USED TO

PRESSURIZE SKID

WITH VAPOR AT

STARTUP

PRV001

PRV002

VLV125

VLV126

VLV127

PRV108

VLV128 VLV129

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Simplified Isometric Pump Skid Drawing

Skid dimensions: 6’ wide x 12’ long

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60 Ton Portable CO2 Storage Tank

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Line Heater Schematic

Source: GPSA Engineering Data Book, 12th Ed, Fig. 8-32

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250 MBtu/hr, Propane Fired Line Heater

24” diameter, 8’ long, 1,800 lb. dry weight on skid

12


Wellhead

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Reservoir Schematics

Source: ISGS, Geobits 8 and 9

The folded rock layers trap the

oil, which is lighter than water

and floats at the top of the

reservoir.

Impervious rocks like shale trap oil and gas in crests

or upwarps of rock layers.

A=anticline trap. R=reef trap. S=stratigraphic trap

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Simulation Results – New Oil Well Case

Simulation Package: WinSim Design II v 9.32

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Simulated Wellbore Conditions –

New Oil Well Case

Pressure, Temperature and Vapor Volume % vs. Wellbore Depth

0

200

400

600

800

1000

1200

1400

0 600 1200 1800 2400 3000

Wellbore Depth (ft)

Pre

ssu

re (

psia

)

0

10

20

30

40

50

60

70

80

90

100

Tem

pera

ture

(F

) an

d V

ap

or

Vo

lum

e %

Pressure

Temperature

Vapor Volume %

Two PhaseLiquid

PhaseDense Phase

CO2 Critical Pressure = 1071 psia

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Conclusions

• Pump skid has been designed to provide maximum

flexibility over a wide range of operating conditions

• System design incorporates safety requirements for

liquid CO2 service

• Pump skid, CO2 storage tank, and line heater

selections ensure oil field suitability and maximum

portability for multi-site, four year project

• Pump skid completion is scheduled for mid-May 2006

• Line heater and CO2 storage tank will also available

by mid-May 2006

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