Past Experiences and Future Challenges for CO2 Injection
CO2 is an effective EOR agent, but its application has mainly been restricted to basins which have significant nearby subsurface sources of CO2, the Permian Basin in the USA being the only large scale example of CO2 flooding. Concerns over the possible link between emissions of manmade greenhouse gases (predominantly CO2) and climate change have led to increased efforts to improve technology to reduce the cost of CO2 capture and introduce fiscal measures to promote CO2 sequestration. In this context CO2 EOR projects can add value by maximising hydrocarbon recovery and provide a possible bridge to a lower carbon emissions future by reducing the lifecycle cost of sequestration. In this article Stephen G Goodyear (Stephen.Goodyear@shell.com) and Peter M Jensen (Peter.M.Jensen@shell.com) of Shell International Exploration and Production B.V. and Norske Shell A/S respectively discuss how Shell’s extensive experience as an innovator and initiator of CO2 EOR in the Permian Basin is being used to meet the new challenges of CO2 injection.
CO2 EOR in the Permian Basin
The Permian Basin of West Texas has a development history going back to 1920. Reservoirs are predominantly light oils in tight carbonates (1-10 mD) at depths of around 6000 ft. Over the years field development has been through primary depletion, secondary waterflooding and finally tertiary CO2 miscible WAG.
CO2 is supplied from three natural source fields (McElmo Dome, Sheep Mountain and Bravo Dome) and transported as a dense phase some 500 miles to the Permian Basin. In the early 1980s Shell developed McElmo Dome (12 Tscf), the largest of the source fields with a supply capacity of 1 Bscf/d. Figure 1 shows the location of the source fields relative to the Permian Basin, and the local CO2 infrastructure that has developed around the main fields.
Figure 1: Permian Basin CO2 Supply Infrastructure
A key milestone in the evolution of CO2 flooding was the pilot test undertaken by Shell in the Denver Unit of the Wasson field. This ‘observation’ test was designed to benchmark models of CO2 EOR by obtaining direct subsurface measurements through logging and coring to determine the way CO2 moved through the formation, and its effectiveness in displacing remaining oil to waterflooding.
The configuration of the observation logging and coring points around the CO2 injection well are shown schematically in Figure 2. The pilot consisted of a period of water injection to establish base line conditions, followed by CO2 injection and then a water chase flood to represent the first cycle of a WAG flood.
Figure 2: Schematic Diagram of Denver Unit Pilot
The observation pilot established three key aspects of the performance of the CO2 injection (Figure3):
- Vertical conformance. Stratification of the reservoir is important with 75% of the injected CO2 contacting only 25% of the oil, with 25% of the pore space unswept.
- Mobilisation of oil. The injected CO2 successfully mobilises waterflood remaining oil, reducing this by around 20 saturation units.
- Injectivity. CO2 has water-like injectivity. After an initial period when water and remaining oil are displaced away from the injector, injectivity rises above the water flood value. Similarly during the water chase flood, after the gas is displaced away from the injector, injectivity rises above the water flood value.
Figure 3: Results from the Denver Unit Observation Pilot
Convincing evidence from the pilot led to the development of natural CO2 sources in Colorado and New Mexico and major expansion of CO2 flooding in the Permian Basin.
Using CO2 sourced from McElmo Dome Shell developed the largest CO2 EOR project in the world at the Denver Unit (Figure 4). This required more than 400 MMscf/d of sustained CO2 injection in over 100 patterns, with more than 200 MMscf/d of gas processing/recycling on site. An active programme of surveillance and management was undertaken, with CO2 EOR implemented across the unit in areas with different subsurface geologies and injection schemes. Shell also successfully tested and applied CO2 EOR to the palæo-oil zone, a naturally occurring residual oil zone which was otherwise unproducible under waterflooding.
Figure 4: Production History of Denver Unit
Maximising the value of CO2 EOR requires a fully integrated subsurface-surface approach with sufficient flexibility to evolve facilities design to reduce cost. For example, treatment of back produced gas needs careful evaluation to determine whether it is best to recompress and reinject the produced gas, or to separate out the hydrocarbon gas, and only reinject CO2. Table 1 summarises some of the key learnings from the CO2 EOR projects undertaken by Shell.
| From | To |
| Simple ‘hands off’ from reservoir engineer to facilities engineer | Iterative flood scenario development to optimise investment of CAPEX |
| Completely new infrastructure | Life cycle view of infrastructure to maximise reuse |
| Gas processing plants | Tailoring of gas treatment options, including direct on-site reinjection |
| Low pressure gathering systems (20 to 60 psig) |
High pressure gathering systems (150 to 300 psig) |
| Use of stainless steel and other expensive corrosion resistant alloys | Use of fibre reinforced plastics, plastic coated/lined carbon steels |
Table 1: Evolution in CO2 Facilities Design Concepts
Implementing a successful CO2 EOR project requires higher levels of surveillance and optimisation compared to waterflood operations. Key surveillance activities include:
- Monitor reservoir pressure to ensure it is above the MMP.
- Monitor injection BHP to ensure it remains below the fracture gradient.
- Monitor injection conformance and profile at well via PLTs and in the reservoir via saturation logs in observation wells.
- Review of exceptional wells and patterns periodically (6 to 8 times per year).
Optimisation of performance requires patterns to be prioritised to maximise the benefit from further CO2, through the refinement of the WAG (Water Alternating Gas) ratios.
Despite its proven track record Shell recognises that new basins for major EOR operations will have different subsurface conditions and must be studied on their own merit. Shell’s record as an innovator in CO2 flooding, demonstrated by its approach to piloting, integrated subsurface-surface modelling, facilities design and CO2 flood optimisation makes it well placed to take on the challenge around the world.
CO2 Capture Technology
In basins where there is no nearby natural source of CO2 the key question is whether anthropogenic CO2 can be captured at a cost that makes CO2 based EOR attractive. This can be achieved through technological improvements which directly lower the cost of CO2 capture, or through fiscal changes that provide a credit for CO2 sequestered during an EOR project.
Shell has made an assessment of best-in-class commercially deployable carbon capture technology, and has recognised Mitsubishi Heavy Industries (MHI) as an industry leader in CO2 capture from low pressure flue gases through proprietary energy efficient solvents and processes, (Figure 5). Shell and MHI have entered into an MoU to explore for efficient ways of combining flue gas CO2 recovery and CO2 EOR based miscible flooding targeting the Middle East region.
Shell is also actively developing new capture technologies through its internal research programme and through participation in joint industry projects.
Figure 5: MHI 3000 tonne/d CO2 Capture Plant Design
CO2 Sequestration
Fiscal regimes that assign a value to long-term CO2 sequestration can also help lower the cost of CO2 for EOR. Shell, like many in the industry, are working hard to have Carbon Capture and Storage (CCS) recognised for earning credits (comparable to efficiency and energy switching programmes) under Kyoto and the European Emissions Trading Scheme.
Combined CO2 EOR and sequestration schemes present an additional set of challenges, compared to pure sequestration projects.
Experience of CO2 EOR operations shows that maximising EOR production requires handling significant volumes of back produced CO2. Additional energy is required for recycle compression and possibly for gas separation. Depending on the oil properties, the produced hydrocarbon associated gas and NGL streams may represent a significant source of revenue, while the MMP of the reinjected gas may be increased by the presence of methane to above the operating pressure of the reservoir. Additional energy demands lead to increased emissions and so it is important to understand the full project lifecycle energy and carbon balance to determine the net sequestration of CO2.
Where the driver for constructing CO2 capture plants is sequestration there will be a requirement for any EOR scheme to provide high uptime, constant CO2 injection capacity. This may place an additional burden on the EOR project, through the need to provide a minimum level of sequestration and the loss of flexibility in terms of planning for an evolving level of CO2 as experience in the response of the reservoir to CO2 EOR is built up. Reconciling these competing requirements and setting a framework of CO2 transfer prices between supplier and consumer requires more complex commercial structures. Linking a number of EOR projects through a common infrastructure may provide the flexibility needed to ensure the availability of injection capacity.
Finally, in a combined EOR and sequestration project, the regulatory framework needs to be clearly established, in terms of any additional requirements over and above the monitoring that would be deployed purely for EOR purposes and the ownership of the liability for ensuring the integrity of CO2 sequestration after field production and EOR operations have ceased at conventional field abandonment.
The Mid Norway Project - An Integrated CO2 Value Chain
Shell and Statoil are addressing the issues raised above through a partnership that seeks to create a unique CO2 value chain in the Norwegian sector of the North Sea. The overall scope of the project is shown in Figure 6.
Figure 6: Schematic Diagram of Shell-Statoil CO2 Value Chain
CO2 will be captured from a methanol plant and from an 860 MW gas fired power station to be constructed at Tjeldbergodden. The power plant will provide offshore power to Draugen, Heidrun, and the gas export facility for Ormen Lange and Nyhamna. In addition it will provide a secure regional onshore power supply. Some 2.5 million tonnes of CO2 will be injected annually for EOR and sequestration, initially at Draugen and then subsequently at Heidrun, with potentially further candidates for CO2 EOR beyond these fields. This is the largest proposed offshore CO2 EOR project. Shell is actively leveraging its Permian Basin experience in the feasibility study of Draugen. Successful development will require a substantial economic contribution from the Norwegian authorities. The investment decision is scheduled for end-2008, with expected startup in 2010-2011.
The overall benefits of the combined value chain approach are seen as the following:
- Large-scale CO2 supply for EOR.
- Improved security of supply.
- Reduction of CO2 and NOx emissions through offshore electrification .
- Industrial utilisation of greener fossil fuel technologies with a global market potential.
- Prolonged field life and increased oil recovery.
- National electricity grid benefits.
Concluding Remarks
Shell has been active in CO2 EOR for 30 years through pilot projects and as an initiator of large scale CO2 transport and EOR floods in the Permian Basin. Each CO2 EOR project is unique and the key to success lies in project design, construction and operation. One size does not fit all and subsurface conditions in reservoirs worldwide will be significantly different from those in the Permian Basin.
Sufficient industrial sources exist if CO2 can be captured at an acceptable cost. Complex value chains linking industrial CO2 sources to appropriate field targets are expected to be a key enabler of new projects. Shell is actively working a number of potential CO2 EOR projects around the world.