The costliest mistakes on CO2 enhanced oil recovery projects aren’t made in the field, they’re made in the planning room. Here’s what Tegre focuses on to keep your project on budget and on schedule.
CO2 has been used for enhanced oil recovery since the SACROC field in 1972. That’s over fifty years of operational experience, and yet projects still run over budget, face unplanned shutdowns, and leave production on the table. At Tegre, we’ve seen why: the decisions that determine project success are made long before a P&ID is drawn, and they require someone who has been through the process before.
This post walks through the critical planning and design considerations for CO2 EOR production and reinjection facilities, from initial scope development through operations. It’s the same framework our team applies on every project we take on.
Start with Scope: The Decisions That Drive Everything Else
Extensive reservoir modeling is the starting point but translating reservoir data into a workable facility scope requires a structured approach. At Tegre, we use a detailed project checklist to ensure nothing falls through the cracks at this stage. The information we require before facility engineering can meaningfully begin includes:
- Number, location, pressures, and volumes for both injectors and producers
- Produced fluid compositions and flow rates (water, oil, and gas)
- CO2 source location, available volumes, pressure, and supply contract flexibility
- Minimum miscibility pressure and required surface injection pressure
- Metering requirements across ownership boundaries
- Lease arrangements, surface ownership, and ROW restrictions
- Plans for produced gas, gas liquids, and increased oil takeaway and storage
- Project schedule and expected injection phases over the project life
Beyond the reservoir data, the engineering team must resolve several operational questions early. What will the production pressure be? Where will facilities be sited? What is the operating philosophy for WAG cycles, injection skids, and production manifolds? What level of automation is appropriate? These aren’t secondary questions, they directly shape capital costs, operating costs, and project risk.
“The decisions that determine project success are made long before a P&ID is drawn. That’s where experience matters most.”
FEED: Where Project Viability is Established
A Front End Engineering and Design study is typically the first formal gate in the project lifecycle. An initial rough-pass estimate, generally accurate to -20% / +50%, is used to evaluate whether the project clears the return threshold. If it does, more engineering time is invested to sharpen the estimate and reduce uncertainty.
What separates a reliable FEED from one that leads to expensive surprises downstream is early attention to project “land mines”, the issues that don’t show up in rules-of-thumb estimates but can dramatically affect both capital and schedule. Tegre builds land mine identification into our FEED process from day one, not as an afterthought.
The Three Facility Categories — and Where the Complexity Lives
Surface facilities for a CO2 EOR operation fall into three broad categories:
- Injection facilities (CO2 source and associated lines).
- Production facilities (satellites, test separators, central tank batteries, and flowlines).
- Reinjection facilities (gas processing, treating, and compression).
Depending on project scale and phasing, these may be centralized or distributed across the field. Each category carries its own set of design decisions and its own potential pitfalls.
Injection Facilities
If the CO2 source pressure exceeds the desired injection pressure, the injection facilities can be relatively simple, choke valves to regulate flow and pressure. When the reverse is true, pumps (for dense-phase CO2) or compressors (for gaseous CO2) are required. Most anthropogenic sources arrive at very low pressure, which can mean significant horsepower requirements.
Pipeline design for CO2 supply lines requires more rigor than conventional natural gas lines. Hydraulic modeling must confirm the CO2 remains above its critical point (supercritical state) throughout the line. Pipe specification needs to address both brittle failure prevention through DWTT specification and testing requirements and ductile fracture arrest capability through appropriate CVN testing. Determining CVN requirements means calculating saturation pressure at worst-case composition using an appropriate equation-of-state model.
A dispersion study and leak detection plan are also standard requirements, along with documented emergency response provisions. These are not optional for a responsible project.
Production Facilities
Most production facilities in a field transitioning to CO2 flood will need to be replaced or significantly reworked, equipment is often worn out, pressure ratings are inadequate, and the fluid handling requirements change fundamentally. One of the highest-leverage decisions at this stage is production pressure.
Producing at higher pressure reduces both capital and operating costs: smaller pipe and equipment, lower reinjection horsepower, lower recurring energy costs. That advantage must be weighed carefully against the impact on production volume and pattern processing time. There is no universal right answer, it is a field-specific optimization that requires both reservoir and facilities input.
Fields transitioning from waterflood often start with dead oil and little associated gas. That changes significantly once CO2 is introduced. In miscible floods, CO2 breaks through with the produced stream. New test separators and production headers must handle higher pressures, greater gas volumes, and corrosive wet CO2. Vapor recovery is required.
Process simulation is not optional here. We have seen sonic velocities in lines and equipment that were improperly sized, the consequences range from erosion to catastrophic failure. Tegre models every system with a process simulator before finalizing equipment selection.
Material selection for flowlines and vessels warrants careful attention. Internally coated carbon steel is widely used in production facilities, but coating selection and specification matter enormously. Piping design must accommodate proper surface preparation, coating application, and inspection which means minimizing spool lengths and offsets, not just specifying the right product. Where paraffin is an issue, flowline materials must also be compatible with hot-oiling temperatures.
Reinjection Facilities
Reinjection facilities range from very simple to full-scale gas processing plants. On the straightforward end, produced gas is reinjected without processing, what the industry calls “blood, guts, and feathers.” Glycol dehydration can be added to reduce corrosion. This approach minimizes capital and works well for projects with little associated gas.
When CO2 separation or gas liquids recovery is required, options include refrigeration, membranes, Ryan Holmes processing, and others. These processes are capital-intensive and do not scale down well, they make economic sense at large volumes and should be evaluated carefully against project economics before committing.
Compression is typically the dominant cost and complexity driver in the recycle facility. CO2 behaves differently from methane: compression ratios per stage in CO2 service run around 2.5, versus roughly 5 for natural gas. The heat of compression is higher, requiring larger coolers. CO2 also changes phase within the compression system, and, just as it is miscible in oil, it will dissolve into many common oilfield materials. Seal and materials specification must explicitly account for CO2 service.
The four land mines that most often blow-up CO2 EOR project budgets: produced water disposal, power availability, fuel gas availability, and startup planning. Address them early or pay for them later.
The Land Mines: What Kills CO2 EOR Project Budgets
In our experience, four issues consistently catch developers off guard on CO2 EOR projects. They are not exotic, but they are consistently underestimated.
Produced Water. Water handling in a CO2 flood is materially different from waterflood operations. CO2 breakthrough changes fluid chemistry and produced water volumes and disposal requirements need to be planned for explicitly not retrofitted.
Power. Electric motors drive most CO2 compressors, and the power requirements for a mature CO2 flood are substantial. Soft starters and variable speed drives can add hundreds of thousands of dollars to a project. Power line construction can sit on the critical path. If a co-op is involved, the operator may be required to fund engineering and construction upfront. Meet with your utility early in the planning phase, not after the compression train is specified.
Fuel Gas. Once CO2 breaks through, field-produced gas cannot be used as fuel without processing. If glycol dehydration is in use, regeneration will require electric heaters in the absence of clean fuel gas. Flare systems in sour-gas fields may require propane on-site as assist gas. These are not afterthoughts, they affect facility design from the outset.
Startup. Startup planning on a CO2 EOR project is genuinely complex. The transition from waterflood to CO2 injection, SIMOPS during facility changeover, early-flood recycle volumes that may be far below design capacity, all of these need to be worked through during design, not discovered during commissioning. Facilities should be designed with safe and efficient expansion in mind as recycle volumes build over the life of the flood.
Operational Readiness: Planning for the Long Run
The design of the facility determines the operating envelope for the life of the flood. Getting it right means thinking through operations during engineering, not after startup.
Turndown and build-out deserve particular attention. The recycle facility will be designed for planned recycle and makeup volumes, but early in the flood, CO2 production will be well below those levels. Equipment that cannot operate efficiently at partial load adds cost and complexity from day one.
CO2 purchase contracts should be structured with volume flexibility, a rigid nomination requirement against a volatile production profile creates unnecessary exposure. WAG cycle management, testing requirements, and compressor operations all affect field staffing levels and automation requirements. The right level of automation is a project-specific decision with real cost and safety implications.
Finally, field personnel must be trained in CO2 hazards and high-pressure system operations. Public awareness programs, contractor orientations, and first responder coordination are not optional considerations, they are part of the operating license for any project of this type.
The Bottom Line
CO2 EOR is a proven technology, but successful projects require more than technical knowledge, they require a disciplined process and hard-won field experience. The issues that derail projects are almost always visible early, to someone who knows where to look.
Tegre brings both. Our team has worked through the full project lifecycle on CO2 EOR facilities, from initial scope development and FEED through detailed engineering, construction, and startup. We know where the land mines are buried, and we know how to design around them.
If you’re evaluating a CO2 EOR project and want to talk through your scope, we’d welcome the conversation.