4.3 Offshore Facilities for the Use of CO2 for Enhanced Oil Recovery (EOR)

4.3.1 Introduction

To date, no offshore facilities have incorporated CO2 into an EOR programme; however, some offshore oil regions like the North Sea actually may have more potential in the use of CO2 for EOR than they have left in the form of primary and secondary production combined.

To implement CO2 for EOR offshore, it is necessary to make major modifications to the means of processing the produced fluids. Not only is it necessary to separate out oil from water and produced gas, but also to decide whether it is economic to separate the produced gas into CO2 for re-injection and hydrocarbon gas for export or to simply re-inject all produced gases. While each project will require its own evaluation, Figure 4.2 provides a schematic of the components for two potential options for the process systems for produced EOR fluids.

The process schematic illustrates two options:

- Option 1: oil and natural gas recovery, indicated by the blue dashed polygon (which excludes component 11 and flow B) and includes the additional mol sieve dehydration, CO2/natural gas membrane separator, export of natural gas, and a higher compression ratio high pressure compressor for re-injection of produced CO2 into reservoir. Alternatively, the membrane separator could be replaced with an amine separation system to remove CO2 from the natural gas.

- Option 2: oil with no natural gas recovery, indicated by the green dashed box (which includes flow B and a lower compression ratio HP compressor (11)) and re-injects all produced gases.

Key:

A Produced fluids

B Combined re-injection

C Export natural gas

D CO2 for re-injection

0 HP separator (vertical)

1 HP separator (horizontal)

2 MP separator (horizontal)

3 LP separator (horizontal)

4 CO2/water separator (vertical)

5 Glycol drying unit

6 H2S scavenger

7 Mol sieve drying unit

8 Membrane separator

9 LP compressor

10 MP compressor

11 HP compressor

12 HP compressor

13 Gas cooler

Figure 4.2 Process schematic for two options

In the event of there being little to no economically recoverable associated gas for either the platform or for sale-to-market, option 2 is the simpler and less costly option. However, if there is sufficient recoverable gas to supply the platform with fuel gas and potentially have some left for market, then option 1 is preferred. Additionally, option 1 should not require a constant supply of diesel oil for power generation but will require more compression power for the lower pressure CO2 out of the membrane separator.

4.3.2 Hazards associated with EOR operation

If an EOR operation is proposed, the designer should be aware that the associated hazards increase compared to those associated purely with storage of the CO2. The main factors in this are:

- Bringing the CO2 to the surface and processing it (in conjunction with other fluids) on the platform.

- The presence of other chemicals (amines and glycol drying agents are mentioned).

- Coincident mixtures of oil and/or natural gas.

- The normal offshore hazards associated with converting the platform from one mode of operation to another.

It is worth noting that the level of equipment required for EOR operations and its additional weight may preclude such a process being installed on an existing platform. It may be more practical to have a new process platform fabricated on shore and brought to site for connection up to the existing platform. The existing platform could be reused for power generation, accommodation, process control and export of produced oil and gas through existing methods. However, it will be necessary to re-route all produced fluids to the initial separation vessel, either by a single pipeline from existing dry trees or by having the wells reconnected to dry trees on the new platform. Redundant process equipment on the platform could be removed, thereby reducing the weight loading and assisting in the overall life extension of the existing platform. Again, conversions of this nature are not unfamiliar to the offshore industry.

4.3.3 CO2 release sources and monitoring in EOR applications

A licensed CO2 storage complex must monitor all emissions of CO2. In an EOR application, this will include not only the emissions from any associated power generation on the platform(s), but also any emissions of CO2 derived from the produced EOR fluids. This is why the Figure 4.2 process schematic concentrates on CO2 separation from the oil and water, before the system dries the CO2, recompresses it, then re-injects it back into the field. While this may appear complicated compared to a number of the amine systems offshore and onshore that vent the captured CO2 to atmosphere, the recycled CO2 is the cheapest CO2 available to a CO2 EOR operator. This is especially true if the operator is penalised for every tonne of CO2 emitted under a trading scheme as part of the CO2 storage operating licence. Additionally, the quantity re-circulated through the field is considerably larger than that removed from gas streams currently on offshore platforms.

In addition to monitoring the escape of CO2 for commercial reasons both fixed and personal monitoring equipment should be provided on platforms where EOR operations are taking place.

4.3.3.1 CO2 release sources from EOR operations

Bringing the CO2 to the surface and subjecting it to a number of processing operations provides the potential for CO2 releases, since the facilities for offshore EOR and reprocessing of the CO2 for reinjection into the oil field are quite extensive and subject to a number of failure modes described in section 3. The additional concerns with respect to releases include:

  1. Small process releases.
  2. Process emissions following the emergency decompression of facilities on the platform.
  3. Accidental releases.
  4. Well leaks (operating and decommissioned).
  5. Releases from the geological formation.

Small process releases can be typified by Figure 4.3. When high pressure CO2 escapes in small quantities, it is quite visible, as it forms an ice ball of CO2 and moisture around the leak and becomes self-sealing. Corrosion as a potential cause for creating leakage pathways is always a concern within the process upstream of the dehydration unit and for this reason stainless steel is normally used in areas where moisture is still present. To mitigate this hazard, wells, production pipelines and risers may be protected using stainless steel liners and corrosion inhibiters.

Figure 4.3 Solid CO2/Ice formation around a pressure gauge with CO2 following release

4.3.3.2 Platform decompression and elastomer choice

In the case of an emergency offshore, it may become necessary to rapidly reduce the pressure of all fluids on the platform. However, one of the concerns with CO2 is that there are certain seals that are used that, while made out of specific elastomeric materials suitable for CO2 under normal operational conditions, may behave differently if subjected to rapid decompression. Liquid CO2 will permeate any seal to some extent, and if it is subject to rapid decompression, the liquid CO2 within the seal material may expand rapidly and result in an explosive decompression within the seal. Figure 4.4 is a picture of such a seal that has undergone explosive decompression, and it is clear that this seal will not function properly over time. In order to manage the hazards associated with this phenomenon, the special nitrogen-flooded mechanical seal was developed for the high pressure CO2 pumps as they could not risk such a result each time the pump was turned off79. However, there are some services where an elastomeric seal is required and this may be subject to future leaks of small quantities of CO2 over time in the event of explosive decompression.

Figure 4.4 Explosive decompression of a seal causing blistering or fracturing

4.3.3.3 Accidental discharges and impact of small process escapes

Small process emissions due to the emergency decompression of facilities on the platform are manageable and minor. They usually provide visible evidence of the CO2. However, CO2 releases, even from small instrument lines, may rapidly result in hazardous levels in confined or unventilated spaces, as indicated by the modelling work described in 3.7.4.6.

Accidental escapes could be significant and life threatening and the hazards associated with inhaling the CO2 have been covered in 3.2.1. Further indications of the sort of hazards associated with CO2 escaping from a riser pipe have been given as a result of the dispersion modelling work described in 3.7.4.3 and 3.7.4.4.

The hazards associated with an escape or rupture associated with equipment at a well or subsea manifold or tee connection were also discussed in section 3.2.1 of this report. Protective structures provide the best defence of these system components, and these are described in Annex A.4. The final forms of escape from a decommissioned well or a deep geological formation are excluded from the scope of this publication but have been addressed in numerous articles and reports80.

79 Table 2.1 shows that CO2 has seven times the µJT of nitrogen, hence expands considerably more when moving from the liquid to the gaseous state.

80 EG, Carbon Dioxide Capture and Storage in Underground Geologic Formations, Dr Sally Benson 2005