Reservoir management and EOR (Task 11)

Task 11 develops technologies for the optimal utilisation of available storage space, and the efficient utilisation of CO₂ for enhanced oil recovery (CO₂-EOR). Investment in both characterising a storage site and developing injection facilities (pipelines, well templates and the wells themselves) is costly and needs to be done before injection can start. Therefore, the operator needs to be confident that the storage site can be used to its full potential. Technologies for this are addressed in Task 11’s two activities: mobility control for increased efficiency of CO₂-EOR and aquifer storage, and optimisation of storage site portfolios.

CO₂-EOR
CO₂ enhanced oil recovery, or CO2-EOR, is the process of injecting CO2 into oil reservoirs to mobilise some of the remaining oil. CO2-EOR has thus far been the only large-scale use of CO2 where CO2 has a positive economic value. Several studies have shown that large-scale CO2-EOR in the North Sea can be profitable for oil prices down to 50 USD/bbl. Industry relevance is therefore evident.

The activity on CO2-EOR in NCCS is mainly relevant for Deployment Case 2 (Link). In this scenario an infrastructure transporting CO2 from European sources to the North Sea is in place and sufficiently large amounts of CO2 are readily available for use in EOR operations. However, CO2-EOR may also be relevant for an extended phase of the first deployment case (DC1), where the amount of captured CO2 is increased beyond 1.25 Mt/year.

The net cost of the overall CCS chain is the main deployment barrier addressed. This barrier can be reduced or overcome by providing value through production of additional oil.

Reservoir management
Optimal use of a storage site is an important issue since it will increase the amount of CO₂ stored for the necessary investments in site development. This means that the total cost per tonne of CO₂ stored will be reduced, which will make CCS more attractive as an emission reduction option and increase the likelihood of the deployment of large-scale CCS. The first few CO₂ injection operations will likely focus on demonstration of feasibility and safety. However, active management and optimisation of the available storage capacity will become important when the injection rate increases beyond a few Mt/year for a single storage site. Good reservoir management will be imperative in efforts to minimize storage-related costs.

Results 2021

In 2021, the work on CO₂ mobility control was presented at two conferences. The work on CO₂ transport and storage network studies resulted in two industry workshops and a journal manuscript. In addition, we welcomed a new vendor with in-kind contributions as a member of the Task 11 family.

Stratum Reservoir, a service provider for the petroleum industry with expertise in core analysis, joined NCCS at the end of 2020. In 2021, their in-kind contribution included a core-flooding experiment to extend the test matrix for CO₂ mobility with commercial surfactants. Work in 2020 investigated the effect of surfactant concentration on foam strength for surfactant systems with high and low partition coefficients (i.e., how much the surfactant prefers to dissolve in CO₂ rather than in brine). In addition, SINTEF Industry and Stratum Reservoir cooperated to identify experimental conditions where relevant surfactant systems have intermediate partition coefficients, and to run a core flooding experiment under these conditions. The results strengthened the hypothesis that surfactant systems with a higher partition coefficient have a more abrupt increase in foam strength as the surfactant concentration increases. This behaviour will be important for selecting surfactant systems for field application, since it can be beneficial that foam strength is maintained also for lower concentrations. With the current experimental results, it seems like this behaviour will be found in surfactants that preferentially dissolve in brine. Placement of the surfactant solution in the storage reservoir could then be a challenge, as it will involve a water injection phase prior to the start of CO₂ injection.

Simulation of CO₂ mobility control was presented in two conference contributions: modelling on core scale at the GHGT-15 conference in March and modelling on field scale for heterogeneous reservoirs at the TCCS-11 conference in June. Both were oral presentations, with short papers for the proceedings.

For the field scale, earlier work to study increased storage efficiency was performed with homogeneous reservoir properties. This year’s work extended this to simulations on a stochastically generated ensemble with heterogeneous reservoir porosity and permeability. The newly developed ensemble simulation facilities of the Matlab Reservoir Simulation Toolbox (MRST) were employed in this work. With heterogeneous properties, the increase in storage efficiency is still significant when mobility control is used; however, the relative increase also shows a large variation from one realization to another (see Figure 1).

Figure 1: CO₂ break-through time is simulated for 100 stochastic realizations of a heterogeneous quarter-fivespot-model both with CO₂ mobility control and with normal CO₂ mobility. The histogram shows the distribution of the relative increase in storage efficiency between normal CO₂ injection and CO₂ injection with mobility control for each realization. The relative increase ranges from 20% to more than 100%. The mean increase (black dashed line) is 54%. The red dashed line indicates the increase for a homogeneous model.

Work on transport and storage network reliability continued. Networks involving several injection sites with varying degrees of built-in surplus transport and injection capacity were subjected to random injection well failures (e.g. due to operational issues that require prolonged maintenance work). The effect of well failure on missed injections (target injection rate minus injection capacity) was calculated in each instance. Results show that the potential costs (emission allowances) of missed CO₂ injection could be of the same magnitude as the cost of increasing the flexibility of the network to a sufficient level (see Figure 2).

Figure 2: Missed CO₂ injection rate in case of a well failure in a network where injection capacity is gradually increased to match anticipated increasing CO₂ supply. For low flexibility factors (little additional capacity), a well failure will lead to relatively large missed injection rate (vented or not captured). Missed injection rate is particularly large in years where the increasing supply rate almost catches up with installed injection capacity. For increasing flexibility factors the potential missedinjection rate is quickly reduced. As the cost for emission allowances is currently at 60 €/tonne and is expected to increase over time, the cost of missed injection is comparable to the cost of increased flexibility (more wells).

Results 2020

Work in Task 11 in 2020 has led to the submission of three journal manuscripts.

Laboratory testing of commercial surfactants for CO₂-brine foam stabilisation has demonstrated significant differences between the surfactant systems in the way the surfactant concentration influences the foam strength. Loss of strength as the concentration is reduced can be gradual or it can be sudden as the concentration falls below a given threshold. This concentration dependence of foam strength is important for the performance of CO₂ mobility control in field application and should therefore be investigated further to provide guidance on the most promising surfactants.

Earlier work in Task 11 has demonstrated that CO₂ mobility control, if successfully applied at field scale, can give significantly increased storage efficiency (the fraction of pore space that is occupied by stored CO₂). This year, we have extended this work with an economic analysis. The economic model includes cost of surfactant purchase and handling, which could be a significant fraction of the total expenses for the storage operation. The benefit of increased storage efficiency could still outweigh the increased costs and give a reduced total cost per tonne of CO₂ stored. Our work shows that this is most likely to occur if the surfactant can be dissolved in the injected CO₂ and if the surfactant preferentially dissolved in the CO₂ over the formation brine. In the most beneficial cases the saving in storage cost is more than 1 € per tonne of CO₂ injected.

While CCS chains in the current pilot and demonstration phases are mostly connecting a single source to a single sink, CCS chains in the later large-scale deployment phases (DC 2030 and DC 2050) could also connect several CO₂ capture facilities to larger transport and storage networks. The transport and storage networks must be developed in such a way that CO₂ supplied by the capture facilities always can be received and stored. The network design has to account for any geological uncertainty remaining after the storage site characterisation and development phases.

In the third manuscript we describe a probabilistic tool for studies of such networks, and apply it to a synthetic case for a CO₂ storage hub development on the Norwegian Continental Shelf. The paper also discusses how possible designs for a pipeline network supplying CO₂ to the storage hub can have different response curves to a random injection well failure. This emphasises the need for flexibility both in the internal transport pipelines in the storage hub and in the injection system.

Generic illustration of a transport and storage network for a CO2 storage hub with several sites — Generic illustration of a transport and storage network for a CO₂ storage hub with several sites

Main results 2019

The NCCS CO₂-brine foam module for the MATLAB Reservoir Simulation Toolbox (MRST) has been used to simulate core flooding experiments with different foam-generating surfactants. The results are compared to actual experiments performed with commercially available surfactants. This is valuable information when screening for surfactant properties that will be most beneficial for field application.

Use of foam is a promising method for mobility control of CO₂in saline aquifer storage. Simulations at field scale indicate that storage capacity can be more than doubled if CO₂mobility control can be successfully applied in the early phases of the injection operation.

Further delimitation of the scope of a tool for optimisation of storage site portfolios has been discussed with industry partners in workshops. The goal is to aid in the decision-making for the development of CO₂transport and storage network through the creation of a tool that calculates the incremental cost of reducing the risk of not being able to store an agreed annual/monthly amount of CO₂. The tool will include probabilistic treatment of the unknown geological properties of storage sites.

Robust risk analysis tools for the operation of CO₂transport and storage networks will enable storage operators to decide the correct level of investment in site characterisation and infrastructure development and the most appropriate timing for the development.

Results from simulation of core flooding with six different foam-generating surfactants. Pure CO₂ is displacing a solution of formation water and 0.5 weight-% surfactant. The plots show the situation after 0.4 pore volumes have been injected. Differences in CO₂ solubility, adsorption and foam strength between the different surfactants lead to significant differences in the development of total surfactant concentration (including adsorbed surfactant) (left plot) and the mobility reduction effect (right plot). Characterisation of such differences are important when selecting an optimal surfactant for field application.

Results 2018

Main results

Laboratory testing of foam-generating properties of synthetized nanomaterials. Results for first batch mainly negative. Design directions for next batch discussed.
Synthetized next batch of nanomaterials for CO₂/brine foam generation
Working version of MRST CO₂-foam module. Simulations with Eclipse and with MRST presented in GHGT-14 publication. Demonstrate >100% increase in CO₂ storage efficiency for five-spot CO₂-injection/brine-extraction patterns.
Initial work to optimize cost/benefit for mobility control in CO₂ storage.
Development of a storage site optimization work flow.

Demonstration of the effect of mobility control for CO₂ in a five-spot well pattern. CO₂ injected at a rate of 0.5 Mt/year through the well in the left corner into a 100-m thick reservoir section with horizontal dimensions 1400x1400 m, while brine is produced at the opposite corner. Top: After 6 years the CO₂ has reached the location of the production well, and this section of the reservoir will have to be closed soon thereafter. Bottom: if mobility control can be implemented, the injected CO₂ will move much more slowly across the reservoir section and will not reach the opposite corner until several years later, giving 50 % increased storage capacity in the shown example.

Results 2017

The mobility contrast between CO₂ and oil/water, and the large well distance, make tertiary CO₂ injection more challenging as an EOR option in the North Sea than in North America, where it is already being successfully employed.

The task investigates novel methods for controlling the mobility of injected CO₂, such as functionalized nanomaterials for foam generation or direct CO₂ thickeners.

Following a review of recent literature, the first series of newly designed POSS (polyhedral oligomeric silsequioxanes) nanomaterials was synthesized.

Testing of CO₂ solubility and other properties will commence in 2018, to give input on further generations of nanomaterials. Mobility control of injected CO₂ can also be beneficial for aquifer storage, since it could postpone the point in time when CO₂ reaches spill points in structural traps. Initial modelling to investigate this effect has been performed.

Publications

Task leader

Alv-Arne Grimstad

Senior Research Scientist

47 03 55 66

Name: Alv-Arne Grimstad
Title: Senior Research Scientist
Phone: 47 03 55 66
Department: Petroleum
Office: Trondheim
Company: SINTEF AS

Norwegian CCS Research Centre