Carbon capture and storage (CCS) is a vital technology in the battle against climate change. As large quantities of carbon dioxide (CO2) will need to be stored, depleted oil and gas fields are prime targets for CO2 sequestration.
During steady state injection of CO2 into a depleted reservoir, it is preferable to keep fluids in the liquid phase while in the well completion in order to maintain a stable hydrostatic head, prevent potential hydrate formation and to avoid equipment damage associated with cooling by thermodynamic flashing and the Joule-Thomson effect. This can be achieved by maintaining pressure in the tubing above the triple to critical point line. Current methods of maintaining pressure include tubing friction or a reliance on sufficient back pressure from the reservoir due to high reservoir pressure or low injectivity.
As carbon sequestration for emissions reduction is a relatively new process, the software available to model CO2 injection, considering the thermodynamics and heat transfer, with multiple flow control devices is limited.
Through nodal analysis, Tendeka has developed a CCS simulator which can mimic the choking effect of downhole flow control devices placed at intervals in the completion that are sized and numbered to achieve the desired pressure distribution and CO2 injection rate in a multi-layered reservoir. The model is currently only suitable for steady state analysis and does not consider transient periods during well start-up or shutdown.
A full explanation of the background to the project, a description and application of the process and equipment, and analysis of the data and results was presented at EAGE 2022. The full paper can be found here: SPE-209705-MS.
Flow control technology
To counter changing reservoir conditions and fluctuating CO2 disposal requirements over the life of the well, the conventional response is to perform a full workover to change the tubing size or develop several wells that come on and off stream. Alternative mitigation methods rely on small diameter, multiple injection strings to restrict the amount of CO2 that can be injected (as shown in Figure 1). Such methods are costly, technically prohibitive and have an impact on greenhouse gas emissions.
A more feasible and sustainable alternative is the use of downhole variable flow restricting devices which will autonomously respond to changing well conditions, without the need for intervention or a workover at a later stage.
Tendeka, a TAQA company, has developed a range of inflow control devices, FloRight ICDs, which can be installed as part of a well completion to create an additional pressure drop to balance production (see Figure 2).
This works on the principle that pressure drop is a function of flow rate and fluid density. Like ICDs, inflow control valves (ICVs) are an active device used to partially or completely restrict flow in a well. They can be surface controlled through downhole control lines that provide electric and/or hydraulic conduits to relay commands to the ICV or operated wirelessly. Communication is via electromagnetic currents, acoustic signals, or fluid harmonics, similar to mud pulse telemetry in drilling. The company’s PulseEight wireless completions technology is the world’s first re-deployable wireless completion with control, power, monitoring and communications already on board (Figures 3 and 4).
The design workflow
The CCS injection simulator is an excel-based model utilising the National Institute of Standards and Technology (NIST) Reference Fluid Thermodynamic Transport and Properties Database (REFPROP) software to calculate the thermodynamic properties and heat transfer of CO2. This allows the number and distribution of the downhole ICVs installed in the upper completion to be manipulated to maintain the CO2 in the dense phase (liquid or supercritical) downstream of the devices. In addition, the simulator can also model the flow through parallel ICDs distributed across the reservoir section.
The design workflow begins by modelling the two extreme injection scenarios – initial conditions and end of life conditions – over the life of the well. In all scenarios, the wellhead injection choke is used to fine tune the CO2injection rate to the target rate, while the equivalent orifice sizes on the interval control valves are adjusted to prevent CO2 flashing while maintaining the target injection rate.
The results are then analysed through comparison of the pressure/temperature versus depth profiles generated by the simulator, thus depicting the envelope of pressures and rates under which the downhole flow restricting devices would be required to work. Through this analysis, it is then possible to determine the required equivalent orifice size of the chokes to effectively control liquid CO2 injection over the range of injection scenarios and reservoir conditions.
Simulating the behaviour and flow of CCS
The upper completion is divided into ten segments from the surface to the top of the perforations or open hole. Each segment length is dictated by variations in the completion geometry and annulus contents, and then up to five zones for perforations or the open hole, as well as other fixed inputs for each injection case. The thermal, conductivity and emissivity values are derived from industry standards for steel, cement, etc.
Up to five inline, PulseEight ICVs, in series, are strategically positioned along the length of the surface injection conduit to the conduit at reservoir depth to maintain the CO2 in the dense phase. Arrays of ICDs in parallel, located at the reservoir depth distribute the CO2 injection into the reservoir layers and provided a minimum amount of back pressure to keep the CO2 in a liquid form in the injection tubing.
As the model is flexible, it can incorporate either more restriction at the surface choke or reduce the number of ICVs required.
As the CO2 transits the injection conduit from wellhead to the reservoir interface, heat is conducted from the overburden through the cement, casing, annular fluids and tubing to increase the temperature of the CO2. The higher the velocity of the CO2 in the tubing, the less time it has to pick up heat, and the colder it arrives at the reservoir. Thus, with flashing to a gas phase, the velocity of the CO2 increases dramatically, and arrives downhole at a much colder temperature.
For each specific reservoir and injection rate case, the variables altered are the quantity of the adjustable downhole chokes (ICVs) and the equivalent orifice size of both the adjustable downhole chokes and the wellhead choke. For instance, decreasing the equivalent orifice size of the choke, restricts the flow while increasing the orifice size, opens the flow.
A solution is found when the flow balance is at zero, meaning the flow in the tubing equals the flow in the reservoir, and the injection conduit line is within the CO2 dense phase boundary.
Further planned developments of the model plan to introduce the ability to incorporate gas mixtures into the model (as opposed to CO2 only) to factor in the impurities which may be present in carbon dioxide, especially when the carbon dioxide is generated from an industrial source.
Accelerating CCS initiatives
The Tendeka investigation has shown that a CCS injection simulator can effectively model the reliability and feasibility of using downhole flow control devices over varying envelopes of injection and pressure scenarios to safely secure and store liquid CO2 long-term.
The results not only support cost-effective alternatives to recompletion or intervention over the life of the well, but most importantly, it can be used to fast-track innovation which will accelerate carbon storage initiatives to reduce emissions and achieve climate change goals.
 SHELL, 2014. Peterhead CCS Project Well Completion Select Report. Aberdeen: Shell UK Limited
Anna Petitt has nine years’ experience with Tendeka. She graduated with MA First Class Honours from the University of Aberdeen and has a Distinction MSc in Oil and Gas Engineering from RGU. Her MSc thesis used the simulator to model flow control devices to maintain CO₂ in liquid form and won the Energy Institute’s best MSc competition.
Michael Konopczynski is a director of subsurface engineering at Tendeka in Houston. He holds a BSc (1981) in mechanical engineering from the University of Toronto. He is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA) and SPE.