Rose Subsurface Assessment

Quantitative risk assessment is required for SCS projects in order to fully capture their complexity, potential impacts, and monitoring requirements over long timeframes. The subsurface characterization of potential CO2 storage sites begins with the evaluation of current risks such as pore volume and injectivity. Many SCS site selection studies have used strategies for assessing current risks that were developed in the oil and gas industry, including common risk segment mapping and the geological chance of success. These approaches typically use a probability scale of 0 to 100% (see Figure below). The identification of future risks, such as storage effectiveness and CO2 retainment, should also begin in the early stages of a project. The frequency of these potential future events should be assessed as the probability of the event occurring in any single year. The probability values in this context are far lower than those used in oil and gas risk assessments, hence an expanded log scale is more appropriate. It is possible to estimate the frequency of some types of future events using empirical data. Several papers have been published that contain data regarding the rates and annual frequencies of these events. Other analogous frequency data that could be used to estimate base rate event probabilities include seismicity data, published reports of hazards and accidents, industry and government information, and detailed reviews of SCS projects.

A staged approach helps identify and mitigate the subsurface risks that can impact a SCS project. Most importantly, this approach incrementally exposes capital as the project evolves so we can make good decisions about whether to continue investing. In general terms, the staged approach can be summarized in a Decision Tree (shown in the Figure below). Note that the tree contains four stages: 1.    An Identification Stage that evaluates whether the discovered volume is significant enough to warrant continued project evaluation. It may not be necessary to drill a well for this purpose. 2.     An Appraisal Stage that drills at least one well to determine whether CO2 can be injected at a sufficient rate to be commercially attractive.   3.     An Injection Stage that drills additional wells (if needed) to inject CO2 and ensures that the reservoir volume and connectivity is sufficient to store the contracted CO2 volume. 4.     A Monitoring Stage that provides confidence that the injected CO2 is staying where intended without any significant leakage outside of the defined storage complex, induced seismicity, or migration outside the boundary of the project area. Our experience is that there will always be a desire to shorten or eliminate some stages. This may be possible if there is plenty of good quality subsurface data and analogs, but this decision cannot be taken lightly. Prematurely removing stages (and their stage thresholds) increases the risk of squandering large sums on failed projects. Careful consideration of the Value of Information (VOI) is also required throughout the process. Information adds value if it affects a decision. Some of the injection projects discussed in previous postings clearly would have benefitted from a VOI exercise. For example, a thorough front-end risk assessment of the Castor project would have revealed the lack of injectivity data and the risk of induced seismicity. This could have prompted an injectivity test, revealing seismicity and avoiding the needless construction of facilities and infrastructure. For any given project, the staged approach can be modified and coupled with a fit-for-purpose risk assessment workflow. These should be modified as the project proceeds, preferably as deliverables from an assurance process. For advice on how to implement such a process, please contact us at Rose Subsurface Assessment. We manage a Risk Coordinators Network consisting of 30+ companies focused on assurance best practices.

Loving this profile on our very own Henry S. Pettingill!

The initial subsurface risk assessment of SCS sites is similar to petroleum exploration. The focus is on quantifying the characteristics of a potential storage reservoir and the chance that it will be discovered. We classify these as current risks, which can be evaluated by drilling a well today. Beyond these are future risks impacting whether we can store some contracted volume of CO2 over a multi-decade project life. Assessment of these risks requires the use of dynamic models calibrated to seismic surveys, injection rates, and other data. Although these models are periodically updated, they are unlikely to provide a complete and accurate view of subsurface behavior, especially beyond the timeframe for typical production operations. As such, they are insufficient for a full risk assessment. There are multiple risk assessment techniques that have been adapted from other industries and applied to SCS projects. Many of these techniques have been published and demonstrated via case studies. However, due to the complexity, long timeframes, and uniqueness of each SCS project, no single existing published risk assessment technique will be universally suitable. Therefore, we advocate defining a robust framework that acknowledges learnings from past projects, utilizes the best combination of existing risk assessment methods for each project, and enables the understanding of project risk to evolve as the project progresses. A key purpose for such a framework is to quantify the risk profile of a project through time, including a determination of those periods of Peak Risk when the system is close to maximum stress and the risk of an event occurring is highest. In developing such a framework, we incorporate the following elements which will be discussed in succeeding posts: 1.    Application of a staged approach 2.    Defining risking scales 3.    The quantitative risking scale 4.    Comprehensive event and hazard identification 5.    Linking events and hazards to impacts 6.    Quantifying the frequency of long-term events 7.    Changes in the risk profile over time and peak risk 8.    The peak risk workflow and results 9.    Review and refinement of risks Read this full series at www.roseassoc.com/blog.

The initial subsurface risk assessment of SCS sites is similar to petroleum exploration. The focus is on quantifying the characteristics of a potential storage reservoir and the chance that it will be discovered. We classify these as current risks, which can be evaluated by drilling a well today. Beyond these are future risks impacting whether we can store some contracted volume of CO2 over a multi-decade project life. Assessment of these risks requires the use of dynamic models calibrated to seismic surveys, injection rates, and other data. Although these models are periodically updated, they are unlikely to provide a complete and accurate view of subsurface behavior, especially beyond the timeframe for typical production operations. As such, they are insufficient for a full risk assessment. There are multiple risk assessment techniques that have been adapted from other industries and applied to SCS projects. Many of these techniques have been published and demonstrated via case studies. However, due to the complexity, long timeframes, and uniqueness of each SCS project, no single existing published risk assessment technique will be universally suitable. Therefore, we advocate defining a robust framework that acknowledges learnings from past projects, utilizes the best combination of existing risk assessment methods for each project, and enables the understanding of project risk to evolve as the project progresses. A key purpose for such a framework is to quantify the risk profile of a project through time, including a determination of those periods of Peak Risk when the system is close to maximum stress and the risk of an event occurring is highest. In developing such a framework, we incorporate the following elements which will be discussed in future posts: 1.    Application of a staged approach 2.    Defining risking scales 3.    The quantitative risking scale 4.    Comprehensive event and hazard identification 5.    Linking events and hazards to impacts 6.    Quantifying the frequency of long-term events 7.    Changes in the risk profile over time and peak risk 8.    The peak risk workflow and results 9.    Review and refinement of risks

Last month our DHI Consortium celebrated a major milestone in Pau. Many thanks to all our presenters and to our hosts TotalEnergies, especially Emmanuel Chavanne who worked very hard to pull it off! Alexis van Lennep Jim Geary Benoit Paternoster Muhammad Nauvall Juliansyah Rose Subsurface Assessment

Any significant event occurring during an injection project should have been foreseen as a possibility. A thorough understanding of potential analogues, the allocation of sufficient time and tools to characterize projects, and the application of techniques to mitigate bias can help ensure this happens. Moreover, the chance of the event occurring can be quantified through additional data gathering and analysis, and the cost of impactful events can be reduced by pilot projects prior to committing to a full-scale project. This requires a strategy that does not unreasonably accelerate development and minimizes expenditures. These are not easy hurdles to overcome, and a concerted effort is needed to address them. Some of the techniques we advocate are framing sessions, a staged approach, peer reviews, external audits, and performance lookbacks. These promote a rigorous assessment of the uncertainties, which reveal the key risks, including those that are not immediately apparent. An understanding of what unexpected events could occur, and what their impacts could be, is crucial. Failure cases should be constructed and shared with the regulator and stakeholders. The use of probabilistic techniques is highly recommended in this process for quantifying project framing, analysis, and risking. Site-specific geological and project characteristics must guide appraisal and decisions regarding implementation. This means the burden is on the operator to quantify and mitigate risks. Failure to do so not only jeopardizes the commercial viability of the project, but can also imperil wider social license if the impact of unforeseen events negatively affects the public. Read the rest of the posts in this series on our blog at www.roseassoc.com/blog.

The last eight posts in our SCS series contained examples of underground injection projects. Each of them encountered events that impacted project results. While some of these events were anticipated, most were not. Building on these experiences, a series of observations can be made. Understanding the subsurface is fundamental for SCS projects, just as it is for hydrocarbon exploration. We begin with homogeneous and isotropic models, and then refine them to approximate the state of nature. In the absence of dynamic injection data, it is challenging to capture the true heterogeneity of the reservoir and its impact on CO2 plume movement (Sleipner project), especially if natural fractures are involved (In Salah project). This has implications for how much fluid can be stored without pressuring-up the reservoir (Snøhvit project) or exceeding the fracture gradient and breaching containment (Tordis project). The thickness of permeable reservoir (Kh) is key for achieving injectivity, which can be diminished by operational problems (Gorgon project) or halted by induced seismicity if geomechanical properties are unknown (Castor project). Once the CO2 is injected, understanding the plume size, geometry, and migration direction becomes critical. Injected fluids may impact offset accumulations (Wilmington and Huntsman projects) and pose significant liability, especially in areas where the pore space is privately owned. These are not easy hurdles to overcome, and a concerted effort is needed to address them. We’ll summarize some of the techniques we use to address these issues in our next post. You can read all the posts in this series on our blog at www.roseassoc.com/blog.

Posting 17 of our SCS series--the Gorgon Project!

Post 16 of our SCS series--the Sleipner Project!