**5.1 CO2 sequestration repositories**

*Enhanced Oil Recovery Processes - New Technologies*

Range: 10–48 t/day Well head 1015.26 to

1595.42 psi

*Operation conditions of injection facilities in Nagaoka, Japan [42].*

Well bottom max. 2755.72 psi

ties in Nagaoka are summarized in **Table 1**.

upstream failure where it will cause the valve to close.

*4.2.2 CO2 injection*

Ordinary rate: 20 to 40 t/day

**Table 1.**

*4.2.4 Fluid separation*

**5. CO2 sequestration**

To avoid two-phase flow that leads to critical damage and cavitation, the pressure downstream of an offshore booster pump should be over bubble point [46].

Well bottom 48°C

Well head 32°C Kept to be "supercritical phase" (at well bottom)

**Injection rate Pressure Temperature CO2 phase**

CO2 might be injected directly into the reservoir if the pipeline pressure is adequate. However, it is likely to bring CO2 onto platform for control pressure or to lift its pressure; certain design considerations should be considered. Below are the injection facilities' operation conditions and the process flow diagram of field test of CO2 injection in Nagaoka, Japan [43]. Some operation details of injection facili-

Risers are the piping that transports the fluid between the offshore platform and the seabed. Flexible risers are used especially on floating production installations. ESDV is placed between the moving pipe infrastructure and the riser to the platform as a safeguard gadget to guarantee no leakage of CO2 when there is failure in platform. It is likely found on the seabed where there is the possibility of heavy things to be dropped on the pipeline underneath during the lifting operation work. Moreover, it is designed to counter any structural failure on the platform and any

Pressure issue related to CCS projects may require extra pumping units due to higher pressure required over long distance. In the event that the pressure drops along offshore pipeline, usually pumps would be placed on an offshore platform [44].

Due to the nature of CO2-EOR patterns, the water production is high, thus leading to the need for large separation capacity with inlet separators dominated with water rather than oil. Moreover, separation is harder because of scale, emulsion, ESP or gas lifting, and asphaltenes. A large CO2 reinjection compressors are needed due to high CO2 production that resulted from back produced CO2 in the system.

Since the industrial revolution, concentration of CO2 and other greenhouse gases increased due to burning of fossil fuels. The measured atmospheric concentrations of CO2 are 100 ppm higher than preindustrial levels [46]. According to report published by the Global Monitoring Division (formerly CMDL) of the National Oceanic and Atmospheric Administration, concentration of CO2 in the atmosphere has increased by 26% from less than 320 ppm in 1960 to 405 ppm in 2017 [47]. Fossil

*4.2.3 Risers, emergency shut down valve (ESDV), compressors, and pumps*

**136**

Several types of subsurface repositories may be utilized for sequestration of CO2. CO2 could be safely sequestrated in subsurface formations such as deep saline aquifers, coal bed methane (CBM), and depleted hydrocarbon reservoirs. Due to known geological formation and existence of seal traps, CO2 may be more safely sequestrated in depleted oil and gas reservoirs as compared to saline aquifers and coal bed methane reservoirs. On the other hand, the abundance and higher storage capacity are two major motivations for sequestration of CO2 in saline aquifers. **Figure 8** illustrates CO2 sequestration in various underground repositories. International Energy Agency (IEA) estimated global geological sequestration (storage) potential of 400–10,000 Gt for saline formations and 900 Gt for depleted oil/gas fields [50]. CO2 sequestration requires comprehensive knowledge of characterization and behavior of CO2, rock and fluid interactions, as well as operation conditions in the geological formation of interest.
