Author: Kate Evans
Technical Advisor, Neftex® PREDICTIONS
Author: Steve Knabe
Global Director for Evaluation and Production
Limiting global warming through the reduction of greenhouse gas emissions is widely acknowledged as one of the key challenges of this century. Many governments, non-profit organizations, academia, corporations, and the public support the effort to tackle this issue. The oil and gas industry, as the primary suppliers of energy and fuel, are in a unique position to help identify solutions for a cleaner energy future. In particular, carbon capture, utilization, and storage (CCUS) has been highlighted as a cost-effective method to mitigate emissions and facilitate the switch to hydrogen fuel. The oil and gas industry has the relevant skills and resources to develop this emerging discipline.
Global warming, its relationship with greenhouses gases, and its impact on the planet are topics that have long been under discussion. In the 1980s, analysis of the Antarctic ice cores and historical records from the National Oceanic and Atmospheric Administration Laboratory, Hawaii demonstrated a clear, increasing trend of atmospheric CO2 content. By 1989, a seminal paper by Berner and Lasaga suggested the negative effects that anthropogenic activity from fossil fuel combustion would have on atmospheric carbon dioxide (CO2) concentrations. Subsequent research, climatic evidence, and lobbying efforts resulted in the Paris Agreement of 2016, which addressed the rise in global temperatures due to human activity.
According to the Intergovernmental Panel on Climate Change (IPCC) 2018 report, the culmination of significant global research, human activities had already caused approximately 1.0°C of global warming above pre-industrial levels, with a likely range of 0.8°C to 1.2°C. Global warming is likely to reach 1.5°C between 2030 and 2052 if it continues to increase at the current rate (IPCC, Special Report, 2018) and between 4.1-4.8°C by 2100 if no action is taken. This may lead to a series of significant impacts on global climate. In order to limit the most harmful impacts, global warming should be limited to below 2°C in total, with a preferred target of 1.5°C. These findings have led to the commitment to net zero emission targets by 2050 from a variety of governments and organizations throughout the world.
Emission reduction has become a major discussion point within the oil and gas industry in the last two years. Shareholders for many major oil and gas, and energy services companies are increasingly demanding environmental responsibility on the part of the companies in which they invest. In addition, younger members of the workforce are concerned for the long-term future of their careers in an increasingly low carbon world. As of Q2 2020, many major oil and gas companies have signed up to the Paris agreement and set net zero emission targets for both their Scope 1 (direct) and 2 (“indirect” from purchased power) emissions. Key focuses include reducing emissions from operations, investing in renewable energy, and CCUS technology.
In line with understanding how the oil and gas industry can help reduce net carbon emissions, this paper focuses on the subsurface storage aspects of CO2 injection projects and shows the key operational practices to take these projects from concept through operation to post operational monitoring. In this paper, we focus on two options led by the oil industry. They are carbon capture and storage (CCS), and the related, and much better understood, discipline of CCUS via Enhanced Oil Recovery (EOR), from which the oil industry can derive learnings to apply to “pure” carbon storage (CCS) projects. They share similar subsurface engineering approaches and requirements for drilling, operating, and maintaining wells. The technologies and protocols used are in most cases interchangeable. Many surface infrastructure elements, like pipelines, compressors, wellheads, and Supervisory Control and Data Systems, are also the same. Monitoring the injection of CO2 and its subsequent movement in the subsurface are essential components of both CO2 EOR and CCS (NPC, 2019a).
The earliest experience of the oil and gas industry with underground storage of CO2 was during EOR projects. This began in the mid-1970’s in the United States of America (US), notably in the Permian Basin in fields like SACROC. About 100 CO2 EOR projects have since been conducted in the US. Using CO2 for the purposes of Enhanced Oil recovery (EOR) will ultimately result in the majority (up to 95 percent) of the injected CO2 being stored permanently in depleted oil reservoirs.
Storing CO2 in deep geologic formations, for the purpose of reducing greenhouse gas (GHG) emissions, began in 1996 with the Sleipner CO2 storage project in Norway. Currently, 19 large-scale carbon capture, use, and geologic storage (CCS) projects are operating around the world, with a total storage volume of about 32 Mtpa (MegaTonnes of CO2 per annum). Ten of these projects are in the United States, accounting for a total storage volume of 25 Mtpa (NPC, 2019a).
Halliburton has long recognized the importance of this technology. In 2009, Halliburton’s then CEO Dave Lesar wrote, “CCS could be key to a healthy oil and gas industry in the coming decades, and we owe it to our customers and our shareholders to help make that happen.” During the last 50 years, Halliburton has successfully provided products and services for far more than 100 CO2 injection projects with over 15,000 wells. Our integrated teams offer a suite of solutions spanning multiple disciplines, from project planning and site selection, through drilling and injection, pipeline services for transport, to post-closure monitoring. From this experience, we have assembled and refined the tools to make CCUS a reality.
Carbon capture and storage (CCS) is fundamentally the process of capturing CO2 emissions from industrial sources, transporting them to a storage site, and then injecting the CO2 for permanent storage in underground geological formations. For more details of this process, see International Energy Agency, 2020; Global Carbon Institute, 2018; UK Government, 2019. IEA scenarios suggest that reducing net emissions without CCUS will double the cost of meeting global warming targets. For difficult-to-decarbonize processes such as cement production and steel, CCUS is a vital emissions reduction technology. The oil and gas industry has the applicable experience to effectively manage the transport and underground storage elements of these projects.
Storage capacity estimates for CO2 vary greatly. The Intergovernmental Panel on Climate Change (IPCC) (2018) and other published research indicate that perhaps 10,000 GtCO2 could be stored in underground reservoirs. Kearns et al. (2017) constructed estimates of global storage capacity of 8,000 to 55,000 GtCO2. However, the storage capacity of all of these global estimates is larger than that required to keep global warming below 1.5°C over this century. Regional availability of storage capacity may not be sufficient, and it requires efforts to have this storage and the corresponding infrastructure available at the necessary rates and times. Options for storage include depleted oil and gas fields, deep saline reservoirs, and un-mineable coal seams.
There are four fundamental phases to developing an underground storage site (Fig 1):
Figure 1. The key stages of planning and executing a carbon storage project.
Additional considerations include the effective plugging and abandonment (P&A) of existing oil and gas assets to be ready for future underground storage projects for CO2. The long-term storage and safety of such projects are a primary consideration, so effective project design and appropriate monitoring considerations are fundamental. Halliburton has a range of solutions to help address these issues.
The table below, from the IPCC special report, shows some of the options available for CCS storage sites.
Table 1: Storage capacity of different geological tanks (multiple sources)
The two most promising types of sites are depleted oil and gas fields and saline aquifers. Depleted oil and gas reservoirs have the advantages of being previously characterized and having production history-matched for dynamic behavior forecasting. They already have the expensive time-consuming surface and sub-surface facilities built. In the case of some non-depleted oil reservoirs, the CO2 can additionally be used for EOR, with the associated economic benefits. However, care must be taken to evaluate cap rock integrity and well integrity in light of previous oil and gas activity. Saline aquifers, on the other hand, have fewer wells than CO2 EOR sites or reservoirs previously used for oil exploitation. This can benefit seal integrity; however, data and characterization are limited and hence carry more risk and uncertainty in terms of understanding the key reservoir features necessary for safe CO2 storage. In addition, more care needs to be placed on evaluating pressure regimes compared to depleted oil and gas fields, where pressure has been lowered by oil and gas extraction.
The first stage of any CO2 storage project is selecting an appropriate site. Using tools such as the Neftex® Predictions portfolio, we can screen for areas that are geologically favorable to the long-term storage of CO2. From this initial selection, the geological, geomechanical, and engineering aspects of a CO2 project can be designed using specialized modelling tools such as the Permedia® CO2 suite. Permedia® CO2, which has been developed with the support of the world's leading industrial and academic organizations pioneering CO2 storage, is a comprehensive software application for addressing all aspects of the workflow necessary for modelling carbon sequestration. It addresses key aspects of CO2 storage workflows: formation storage prospecting, capacity estimation, well injectivity, formation pressurization, plume trapping, and dissolved CO2 dispersal through specific modules.
Figure 2 shows important aspects to consider during the design phase and the different technology options for better EOR performance. All these technologies are available from Halliburton; see https://www.landmark.solutions/ and https://www.halliburton.com/en-US/ps/default.html?node-id=h8cyv98a.
Figure 2. CO2 EOR Technologies associated with key design aspects for CO2 injection schemes.
In the early stages of any underground storage process, time and attention needs to be paid to the modelling aspect of the work. Due diligence and model evaluation need to be carried out to ensure that the proposed site reservoir is suitable for storage. There are five key conditions for a reservoir to be a good candidate for a CO2 storage “tank” (NPC, 2019a):
As previously noted, the methodologies and technology of oil exploitation and CO2 EOR are applicable to geological storage. However, the specific characteristics of the reservoir make each project unique, and care must be taken to understand many aspects of the reservoir and seal, such as geomechanics, reaction to dynamic pressurization, and sealing capacity.
Unlike EOR monitoring operations (which are primarily concerned with gathering data to understand operational efficiency), dedicated CO2 storage monitoring focuses on understanding and predicting the fate of the CO2 plume. Both processes, however, use similar monitoring technologies.
Specifically, reservoir management workflows used in the oil and gas industry that apply to CO2 injection projects include the following practices:
The worth of CO2 EOR for decarbonization was controversial. Injecting a new gas into a reservoir creates residual gas saturation. Therefore, any reservoir can retain CO2 equivalent to 5-20 percent of its total pore volume (PV). CO2 EOR projects have demonstrated that CO2 injected in reservoir rock can block former water-filled pores and effectively be trapped. In addition, a CO2 fraction remains as a movable phase.
In Water Alternating with Gas (WAG) injection projects, the most common form of CO2 EOR, the relative permeability to gas can decrease with each cycle of injected water, leading to additional trapping of CO2 in the reservoir.
If the injected volume is larger than the total pore volume (PV), the CO2 has to break through to producing wells. Frequently, that occurs long before the 1 PV injection due to channeling and a non-favorable oil-gas mobility ratio; proper flooding design mitigates this problem. In a breakthrough situation, due to environmental and economic reasons, it is important to recycle the CO2, as the industry now does. Despite such challenges, CO2 -EOR is certainly of value for decarbonization.
Above the miscibility pressure, the CO2 is highly soluble in crude oil. This causes:
These effects result in CO2’s oil sweep efficiency being among the highest of EOR injection fluids by weight of fluid injected.
A key step in early stages of CO2 EOR projects is the selection of the injection scheme; Figure 3 shows some of them. Another key step is the flooding design, including the best value ranges of the injection-withdrawal decision variables. The petroleum engineering community knows that a bad design, even with good execution, results in poor results. A proper design requires numerical simulation of a large number of scenarios. For the simulations, we need: 1) good reservoir characterization and laboratory generated input data, and 2) a good reservoir model in a robust numerical simulator like the industry’s first cloud native Full Scale Asset Simulation, a DecisionSpace® 365 cloud application. Full Scale Asset Simulation is the first cloud-native, fully coupled simulation software service for extensive scenario analysis to optimize a field development plan. Usually, a small pilot test precedes the full field deployment; Mogollón (2017) described the pilot steps.
Figure 3. CO2 injection schemes implemented in the field (Modified from Jarrel et al. 2002), being the WAG/water and the tapered WAG/water the most frequent.
Let us consider that the combination of decision variable options, e.g. injection rates and volumes, batch sizes, number of wells, artificial lift types, etc., generates thousands of scenarios. The narrowing down of the simulation scenarios requires deep engineering knowledge. Given this situation, it is very efficient to use advanced tools, in particular a stochastic optimizer like Landmark’s DMSTM software to automatically link the sub-surface, surface models and economic models. The machine uses smart algorithms to search the best scenario, i.e. the one that optimizes the selected objective function, and thereby generates superior results. The objective function can be of a production and/or economic nature, for example oil production and Net Present Value. Additionally, stochastic simulation runs calculate the risk introduced by the uncertainty variable. Figure 4 illustrates the workflow we proved with different EOR types; for more information on this topic, see Mogollón (2017), Mogollón et al. (2018), and references therein.
Figure 4. Numerical optimization workflow for EOR (modified from Mogollón 2017)
Contacting the maximum amount of oil-saturated reservoir rock with CO2 results in a maximization of both the oil recovery and the CO2 trapped in the subsurface. This is achievable by a number of strategies (NPC, 2019b); we refer here to two of them related to the use of advance modelling and reservoir engineering knowledge. Firstly, the use of geo-modeling and reservoir engineering configured in a way to improve subsurface characterization, and secondly, optimization of the WAG (Water Alternating with Gas) scheme to maximize CO2 sequestration.
The vertical and horizontal conformance control increases sweep efficiency and hence CO2 sequestration. Halliburton has developed a well-known suite of chemical and mechanical solutions, which include gels, relative permeability modifiers, and autonomous valves to manage conformance.
An example of how these solutions have been implemented can be found here.
The combination of WAG injection and control valves placed downhole is a technology (WAG-CV) patented by Halliburton. It manages the injection fluids’ distribution, improves the sweep efficiency by controlling channeling, and delays gas breakthrough. A workflow that incorporates smart algorithms controls the gas-to-water injection cycles by zone and slug volume. At a given time, water and gas are injected in different zones. Figure 3 shows promising results in terms of improved oil recovery from numerical simulation for an injection well and a producing horizontal well located 3,000 feet (914 meters) apart, each with 4,000-foot (1,219-meters) laterals and six permeability zones ranging from 10 md to 150 md (Carvajal et al., 2014).
Figure 5. Comparison of WAG-CV with traditional flooding methods (After Carvajal et al., 2014)
This section presents operational aspects that need to be considered early in the design for a successful CO2 project. Over time, initial concerns around the need for expensive metallurgy throughout the injection and production systems were largely allayed as the industry found alternative solutions.
For CO2 injection systems, the following materials are often used:
CO2 EOR projects in the United States have relied on purchased CO2, which has come from underground deposits of CO2 that have been connected by pipeline to fields in producing areas like the Permian Basin. Since producers have to pay to acquire CO2, they have developed cost-effective technologies to recover and re-inject it. Common gas processing plants in fields using CO2 EOR in the Permian Basin include the following key components, all of which involve well-proven technologies:
Given the maturity of fields where CO2 EOR is carried out in the Permian Basin, inlet gas composition often approaches 90 percent CO2.
As has been discussed, critical aspects of the subsurface must be successfully characterized to enable suitable site selection for the safe and effective long-term storage of CO2. Specific aspects of this process are prospecting for new storage sites, understanding cap rock integrity, predicting the long-term fate and risks of a storage site in the post operational phase, and understanding CO2 injection rates and injection interval pressures. Permedia CO2 software, which has been briefly described above, is a key component of this evaluation process.
At the beginning of a carbon sequestration project, it is important to address the following questions: Where can we store CO2, how much can we inject, can we store it safely, is there enough capacity over the project lifetime, can we inject at sufficient rate, and will the CO2 remain in the geological storage unit? Permedia CO2 software can help reduce considerable risk and uncertainty regarding these questions, make subsequent decision-making on site selection more cost-effective, and ensure that critical elements of the subsurface are understood with more confidence.
The available CO2 underground storage capacity is large enough to meet 2030 decarbonization targets, therefore is expected to play a major role in years to come.
Although there are few CO2 underground storage cases, their similarities with the exploitation of oil and gas fields, particularly those in which fluids are injected, are apparent based on the technologies and methods needed. The field development planning methodology is applicable in both cases, as are many of the reservoir characterization, numerical simulation, drilling, completion, and injection technologies.
Among service companies, Halliburton pioneered decarbonization. In the last 50 years, the company has been involved in over 100 CO2 projects with over 15,000 wells. Halliburton’s comprehensive and constantly improving software suite and experienced consulting and field operations capabilities are available for urgently needed CCUS projects.
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The authors would like to acknowledge the contributions to this article of José Luis Mogollón, PhD, who provided expert guidance and insight into Enhanced Oil Recovery.