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Hydrogen is one of the key components in clean energy systems of the future (Hydrogen Council, 2017). Currently, clean hydrogen production requires either availability of large quantities of renewable energy (in competition with other high power demanding industries) in a capitally expansive electrolysis process or need for carbon capture and storage solutions for the steam methane reforming process. Hydrogen Source developed and is commercializing Hydrogen Generation from Hydrocarbons Subterrain technology allowing to reduce both costs and associated emissions. The process allows converting non- commercial gas reserves to clean hydrogen available for recovery and commercial use with costs considerably below today's state-of-the-art hydrogen production technologies such as electrolysis or steam methane reforming. The paper presents the experimental studies, including adiabatic reactor, core, and combustion tube experiments, confirming process efficiency and simulation studies using state-of-the-art reservoir simulation tools, laying basis for technoeconomic evaluation of the process at the field level. Experimental investigations confirmed process efficiency. Numerical simulation, monte-carlo and P10-P50-P90 statistical analysis showed hydrogen production costs on the scale of 0.1-0.5 $/kg with low associated emissions. Techno-economic estimates of application to several field case evaluations for offshore and onshore hydrogen production are presented. Potential for technology application worldwide is also presented.

In Europe, one of the hurdles to successful deployment of Carbon Capture and Storage projects is a lack of available infrastructure. Creating the whole value chain infrastructure for each individual project is as a rule prohibitively expensive, specifically due to the lack of government support in many of the member states. One potential way of tackling the issue is to create business cases for the stakeholders and therefore reduce the financial burden by utilizing the captured CO2. Out of the available CO2 utilization options available at the moment, CO2-EOR (Enhanced Oil Recovery with CO2) is the only one capable of continuously utilizing large volumes of carbon dioxide while at the same time creating a profitable revenue stream, and then allowing smooth transition into permanent storage and deployment of large scale CCUS. CO2-EOR combined with storage allows for just transition to new energy sources in regions heavily dependent on hydrocarbon production / processing / power generation. In the last 5 years NORCE Norwegian Research Center AS was actively involved in research for CO2-EOR combined with storage. This paper summarize approaches, concepts and findings from projects like REPP-CO2 (project supported by Norway Grants from the CZ-08 Carbon Capture and Storage programme), ENOS (project funded by the European Union’s Horizon 2020 research and innovation programme under grant agreement No 653718), ECO-BASE (supported by Gassnova, Norway; RVO, Nederland; UEFISCDI, Romania; TUBITAK, Turkey; and is co-funded by the European Commission under the Horizon 2020 programme ACT, Grant Agreement No 691712) and STRATEGY-CCUS (funded by European Union’s Horizon 2020 research and innovation programme under grant agreement No 837754). In this paper we present and discuss: • Potential approaches to early stage evaluation of CCUS value chains under large uncertainties for mature or abandoned hydrocarbon reservoirs; • Outcomes of the evaluations, benefits and hurdles from evaluation of several potential CCUS clusters in Europe. The key findings are: • Mature or abandoned hydrocarbon fields onshore Europe are available and suitable for CO2-EOR with subsequent storage; • Fields are often located in vicinity of other industrial installations (cement, steel, refinery, power plants) allowing for short-distance transport and, potentially, for better public opinion as the general public is familiar to and involved in ongoing industrial activities; • Based on experience with CO2-EOR in several locations in Europe and accounting for wide-spread application in the US, preliminary evaluations show that the overall operations may be economically feasible with ETS credits without additional government funding; • If CO2-EOR operations are followed by storage, for some of the candidate fields, the injected and stored CO2 volumes may compensate for emissions associated with recovered oil and gas during the entire field lifetime. This has been shown for some of the candidate fields that has been studied; • Many of the potential CCUS projects need to find the business opportunities and ways to “link” all stakeholders together. Tackling some of these aspects are addressed in detail by e.g. “CO2-EOR business opportunities in Romania and Turkey” by Bos, et.al. submitted to the same conference; • Lacking, or too complex legislation may provide a significant hurdle to the project deployment; • Public dialog is a vital component of establishing the project as shown by both positive and negative examples worldwide.

As a UNFCCC accredited Research NGO, CO2GeoNet has been deeply involved in bringing the science behind CO2 storage and the rationale for Carbon dioxide Capture and Storage (CCS) to a wide range of stakeholders (including the general public) before, during and after the COP21 Climate Conference in Paris. Key messages on CO2 storage, informed by dialogue with numerous stakeholders, are presented here. The overarching conclusion is that collaboration is needed at an EU and a global level to deploy CCS, a viable and flexible technology ready to play an essential role in completing the climate change mitigation portfolio.

REPP-CO 2 is a Czech-Norwegian project representing a major step towards CO 2 storage in the Czech Republic. The project is an advancement towards a pilot project in geological settings with large CO 2 storage potential in the future. The presented work is focused mainly on static long-term laboratory experiments in CO 2 -rock-brine systems. Both equilibrium and kinetic geochemical modelling studies on CO 2 -rock-brine interaction were consequently carried out using geochemical program PHREEQC. The results from experiments and simulations could support the risk assessment argumentation of the storage site performance.

LBr-1 is a small depleted hydrocarbon field in the Czech part of the Vienna Basin. Within REPP-CO2, a Czech-Norwegian research project, a consortium of 7 partners is making the first steps towards obtaining a storage permit and realization of CO 2 injection in future. The work includes collecting the necessary data; conducting laboratory investigations; constructing a three-dimensional geological model of the storage complex, developing dynamic models to be used for simulation of the CO 2 injection phase and post-injection one; executing a risk analysis, and compiling a monitoring plan. The project represents the first step in development of the LBr-1 site towards a research CO 2 storage pilot in the Czech Republic. Fundamental milestones of site assessment, site characterisation, CO 2 injection simulation and risk analysis have been achieved, and plans for further stages of site development have been elaborated. The work is now continuing within the ENOS project funded by the EC within the Horizon 2020 programme, with the final vision to start CO 2 injection around 2020.

To meet the ambitious target set out in the Paris Agreement to keep the temperature rise well below 2°C, all the tools available for reducing CO2 emissions, including CO2 Capture, Utilisation and Storage (CCUS), are needed to meet the challenge. Global collaboration is key in advancing CCUS. CO2GeoNet, a pan-European scientific body on CO2 geological storage, has gained visibility and recognition in the European and global arenas, participating in research and providing scientific advice, training and capacity building, and information and communication. A summary of CO2GeoNet’s cooperation activities with countries outside Europe and with international bodies is given here. CO2GeoNet is open to further opportunities as the Association views global cooperation as critical to accelerating the development, recognition and deployment of CCUS as an important and flexible climate change mitigation technology.

In the H2020 project ENabling Onshore CO2 Storage in Europe (ENOS), research and development at five field sites takes a prominent role. Each of these gives attention to particular challenges or different applications of injected CO2. Research initiated on three of the five pilot sites gives an overview of which different challenges will be tackled and how they are approached. These include the direct geological and technical challenges of CO2 injection (Hontomin), oil production compatible with the climate-energy nexus (CO2-EOR, LBr-1), and the integration of geological storage in CO2 capture and utilisation schemes (Q16-Maas).

Summary Broad availability of continuous pressure measurements from Permanent Downhole Gauges (PDGs) has revived interest in using Pressure Transient Analysis (PTA) to improve history matching of reservoir models. Reproducing pressure transient responses in reservoir simulations as a way of conditioning parameters and realizations of geological models, also known as geological well testing, is a rapidly growing R&D area with many applications recently reported. The main focus of this paper is integration of PTA into reservoir simulation. We present a workflow which combines time-lapse PTA, employing analytical, single-phase models, with smooth transition to numerical, multi-phase simulations. Application of this workflow is illustrated by a case study with horizontal well injection into a segment of a fractured carbonate reservoir. The value of using pressure derivative in history matching is demonstrated through the evaluation of a hypothesis of well connection to conductive faults. The analysis of pressure transients in combination with numerical simulations finally argued for absence of such connection for the analysed history period.

Understanding of flow barriers in a saline aquifer evaluated for geological storage of carbon dioxide is the key point for decision making and designing injection operations. The barriers may significantly limit injection capacity, while their dynamic behavior during the operational phase, like fault reactivation and leakage out of the target formation, may cause unexpected completion of injection phase and have negative environmental consequences. The pressure data obtained in real-time during well testing and main phase of injection with installation of Permanent Downhole Gauges (PDG) may be utilized to characterize and monitor reservoir boundary conditions. Here, Pressure Transient Analysis (PTA) can be employed as interpretation tool. In this work, the case of faults acting as flow barriers including scenarios of sealing and leaking faults is studied using the history of CO2 injection into the Tubaen formation of the Snohvit field as testing data set. The paper starts from answering general questions on applicability of PTA for CO2 injection, related to capabilities and limitations of single-phase flow models. It continues with suggesting and testing approximate approaches to improve the capabilities of such models to deal with CO2 injection cases (brine replica). Finally, an integrated workflow (or a technology, if combined with well surveillance system) for characterizing and monitoring flow barriers in geological storage projects is suggested. This workflow uses advantages of the models above for real-time data analysis. The paper concludes with recommendations for pre-injection well testing and surveillance during main injection phase, closing the loop with application guidelines.

To meet the ambitious EC target of an 80% reduction in greenhouse gas emissions by 2050, CO2 Capture and Storage (CCS) needs to move rapidly towards full scale implementation with geological storage solutions both on and offshore. Onshore storage offers increased flexibility and reduced infrastructure and monitoring costs. Enabling onshore storage will support management of decarbonisation strategies at territory level while enhancing security of energy supply and local economic activities, and securing jobs across Europe. However, successful onshore storage also requires overcoming some unique technical and societal challenges. ENOS will provide crucial advances to help foster onshore CO2 storage across Europe through: 1. Developing, testing and demonstrating in the field, under “real-life conditions”, key technologies specifically adapted to onshore storage. 2. Contributing to the creation of a favourable environment for onshore storage across Europe. The ENOS site portfolio will provide a great opportunity for demonstration of technologies for safe and environmentally sound storage at relevant scale. Best practices will be developed using experience gained from the field experiments with the participation of local stakeholders and the lay public. This will produce improved integrated research outcomes and increase stakeholder understanding and confidence in CO2 storage. In this improved framework, ENOS will catalyse new onshore pilot and demonstration projects in new locations and geological settings across Europe, taking into account the site-specific and local socio-economic context. By developing technologies from TRL4/5 to TRL6 across the storage lifecycle, feeding the resultant knowledge and experience into training and education and cooperating at the pan-European and global level, ENOS will have a decisive impact on innovation and build the confidence needed for enabling onshore CO2 storage in Europe. ENOS is initiating strong international collaboration between European researchers and their counterparts from the USA, Canada, South Korea, Australia and South Africa for sharing experience worldwide based on real-life onshore pilots and field experiments. Fostering experience-sharing and research alignment between existing sites is key to maximise the investment made at individual sites and to support the efficient large scale deployment of CCS. ENOS is striving to promote collaboration between sites in the world through a programme of site twinning, focus groups centered around operative issues and the creation of a leakage simulation alliance.

CO2 injection into saline aquifers causes fast pressure diffusion in large reservoir domains due to low water-rock compressibility. This gives a possibility to enlarge explored reservoir domain using pressure transient analysis (PTA). Installation of permanent downhole gauge (PDG) in the well injecting CO2 into the Tubaen formation of the Snohvit field provided pressure recording during three years of injection history with many shut-in periods. Analysis of time-lapse pressure transients from both injection and fall-off periods revealed unique pressure derivative trend indicating flow barriers. This inspired the use of analytical reservoir model to match both pressure transients and the whole injection history. Usually PTA provides input data for reservoir simulation reducing uncertainty in history matching. Another advantage of PTA models is highlighted in this study: capability of long-term injection performance forecast. The field case confirmed that a reliable model may be assembled based on interpretation of a single injection or fall-off pressure response (e.g. well test prior to injection), which provides accurate forecast. Such a well test, interpretation and forecast do not require in-depth reservoir characterization and simulation. The key point is accounting for major features of the reservoir governing injection performance such as aquifer size and flow barriers.

Water flooding of stratified reservoirs often resulted in non-uniform oil displacement and fast water breakthrough in high permeability layers. Increase in oil recovery may be achieved by improvement of oil displacement in different layers and getting simultaneous water breakthrough in production wells. A similar problem may arise when water flooding multiple reservoirs with constrains on total injection / production. Control of injection rate allocation may provide uniform oil displacement in a layered formation or multiple reservoirs. Constrains on local (per layer) and total (per formation) injection / production rates and on production period for each layer may be accounted for. In this study optimization algorithms have been developed to determine an optimal strategy enabling maximum possible oil production with minimum possible water cut from a group of non-communicating layers or reservoirs. A solution of the optimization problem was found using linear and discrete programming methods under an assumption of two-phase piston-like incompressible flow in the reservoir. An optimal strategy with maximum oil recovery is defined under constrains on local and total production rates, injection start-up time and duration of production period for each layer or reservoir. An analytical solution was also found for a partial statement of the problem, where injection rates remain constant over the whole production period, which in turn is the same for all layers. The general problem statement has flexible constrains available, while the analytical solution for the partial statement may be easily implemented and used without dimension (number of layers or reservoirs) limitations. Both solutions were coded and further tested at mechanistic reservoir models to confirm applicability and efficiency of the developed algorithms in the reservoir simulation practice. A two-dimensional cross-sectional model with non-communicating layers was set up to test efficiency of the optimization algorithms for a typical reservoir simulation problem where fluid / rock compressibility and relative permeability effects are accounted for. The reservoir simulation results have confirmed that the optimal solution remained in force and therefore the optimization algorithms may be successfully integrated in reservoir simulation workflow.

This paper presents an evaluation study and some latest advances in a multi-stage approach to selection of EOR strategies. The essence of a multi-stage approach is in combination of first-order screening based on ranges for critical oil parameters, statistical data from the world wide database, analytical modelling of IOR/EOR process and economic / risk evaluation. Screening and analytical methods are often used for fast preliminary evaluations of various EOR scenarios. Advantages of this approach are its speed, relatively small amount of data necessary to estimate the recovery of a particular EOR technique and a dispersion free analytical solution. Simplified representation of the reservoir used in analytical simulation aids in understanding dominating effects and forces and may be used to verify numerical results. The approach is viable and practical when a large number of reservoirs are to be screened for EOR applicability or when a decision over a new asset with limited field data is to be made. This paper presents new database and improvements in cluster analysis used for estimation of recovery factor. We present a new flexible methodology allowing adding or removing database entries followed up by re-clusterisation and finally cluster-analysis based evaluation of the recovery factor. A new improved methodology to evaluate performance of the WAG injection is discussed. A three phase compositional path (based on realistic relative permeabilities and rock properties) for each simulation layer is used to determine residual oil saturation to WAG. This value is later on used in analytical evaluation of WAG performance. Economical evaluation would be integrated into the tool allowing performing economical analysis based on the analytical production profiles calculated within the tool or external data. The economic evaluation may be carried out in "simplified" or "advanced" mode. Advanced mode allows more detalization in specifying costs, while simplified model allows for faster economical evaluation when in-depth economical evaluation is not possible. Finally a case study of an actual reservoir is presented illustrating how the "EOR compass" could be used in real life situations. The field case presented illustrates screening a new asset as a gas injection candidate. The field in study was taken through a three stage technical evaluation looking at applicability of key development strategies, comparing to the available field cases in the world and finally performing a sensitivity study using an analytical layered model.

The efficiency of carbon dioxide (CO2)-flooding in highly heterogeneous reservoirs may be low due to poor macroscopic sweep. One of the possible ways to increase macroscopic sweep efficiency is by reducing the CO2 mobility by foam. Retention of the foaming agent during CO2-foam flooding is an important aspect affecting both technical and economical potential of the process. This paper presents both experimental and numerical simulation studies performed to investigate the retention of CO2-foaming agents in heterogeneous carbonate reservoirs. These reservoir types consist of high permeable "thief zones" - fractures or high permeable layers and the rest of the reservoir - matrix or low permeable layers. The retention of CO2-foaming agent was studied in flow-through laboratory experiments with CO2-foaming agents; branched ethoxylated sulphonates with different ethoxylation degree in outcrop Liege chalk rock at 55°C. The retention of the foaming agents was determined by breakthrough curves based on chromatographic separation between the foaming agent and a tracer. The flow-through retention experiments were reproduced in a numerical simulator. The results indicate that the retention (the amount of foaming agent lost per rock weight) depends on the type of foaming agent and oil saturation. It is concluded based on simulation results that the amount of the foaming agents retained in heterogeneous reservoirs would strongly depend on its transfer mechanism from high into low permeable zones. The diffusion process is slow and therefore the foaming agent might penetrate only into a certain fraction of the matrix blocks or low permeability layers during the project life time. The retention of the foaming agent in these heterogeneous carbonate reservoirs may therefore be much lower than estimated based on viscous floods. A numerical model describing diffusion and retention by adsorption was established. A good match between experimental and modeling results was obtained without individually tuning the numerical model for each specific experiment. Additional simulation results showed that on the field scale the amount of foaming agent retained in heterogeneous reservoirs will depend on the number of high permeable zones and the size of the matrix blocks.

Screening and analytical methods are often used for fast preliminary evaluations of various EOR scenarios. Screening is typically performed using real field experience and knowledge data bases, which summarize application of EOR methods to similar fields. Analytical methods are limited by simplified representation of the reservoir and EOR processes; however solutions are exact and not affected by the numerical dispersion. Often an analytical solution is used to verify numerical results. The advantages of analytical methods are in their speed and relatively small amount of data necessary to estimate the recovery of a certain EOR technique. The approach is viable and practical when a large number of reservoirs are to be screened for EOR applicability or when a decision over a new asset with limited field data is to be made. A three-level approach to selection of EOR strategies is suggested. First the screening model allows for a fast first-order screening of key EOR applicability methods at given reservoir conditions. The applicability assessment is based on ranges for critical reservoir parameters, using a multi-criterion model and distribution functions. Than the model for oil recovery factor estimation based on the statistical data from projects carried out world wide is applied. Finally, analytical methods could be used for quantitative analysis and production profile calculations for main oil recovery methods: Depletion, Waterflooding, Cyclic Waterflooding, Polymer, Surfactant and Polymer/Surfactant flooding, Immiscible and Miscible Gas (CO2, N2, HC) flooding, Steamflooding and Immiscible WAG injection. A wide range of reservoir parameters and computed results enable the user to perform rapid and comprehensive reservoir analyses as well as sensitivity studies. A unique feature of the developed program is its capability to handle a series of scenarios in only one single run. This tool can be compared with a “compass” helping reservoir and petroleum engineers to identify and successfully implement EOR/IOR methods at their fields.

In fractured chalk reservoirs with low matrix permeability, molecular diffusion and retention of the foaming agent will control the transport of the foaming agent solution from the fracture into the matrix as well inside the matrix. However, the transport of CO2-foaming agents and how much of the matrix will be contacted by the CO2-foaming agent in fractured chalk reservoirs has not been investigated. This paper presents both experimental and numerical simulation studies performed to investigate the transport of a CO2-foaming agent from a fracture into an outcrop chalk core plug at two different temperatures; room temperature and 55°C. Plugs with different water saturations were used; Sw=100%, Sorw (20-30%) and Swi (14%). The fracture was created by transferring plugs with different diameters into cylinders with an annulus space around the plugs. The fracture volumes were filled with different initial concentrations of CO2-foaming agent solutions. The experiments were monitored by taking fluid samples from the space above the fracture at different times until constant foaming agent concentration in the fractures. At different exposure times, the plugs were demounted and samples taken from the outer, middle and centre portions along the whole lengths of the plugs. These samples were analysed for foaming agent concentration to determine the transport rate in the matrix. Results indicate that the transport of the foaming agent solutions into the plugs depend on the diameter of the plugs, temperature and amount of oil remaining in the plugs. The transport of the foaming agent solution from the fractures into the plugs was also modelled with the CMG's commercial reservoir simulator STARS. A good match between experimental and modelling results was obtained. Based on simulated results, the foaming agent was also observed to penetrate and reach the middle sections of the plugs with and without oil. Additional simulation results show that on the field scale, the transport of the foaming agent will depend on the size of the matrix blocks, rock type, and adsorption of the foaming agent as well as the presence of oil.

Field trials and laboratory tests of CO2-foam have shown some success. A number of CO2-EOR field trials with either miscible or near miscible gas injection have shown that foam can lower the mobility of CO2 and improve the macroscopic sweep efficiency. However, not much work about CO2-foam flooding in fractured chalk reservoirs with low matrix permeability have been published in the literature. During CO2-foam flooding of fractured chalk media, it is expected that the injected fluids will flow in the high permeability fractures where foam will preferentially be formed. This will increase the local resistance to flow and divert more of the CO2 and CO2-foaming agent solution into the low permeable matrix.This paper presents results from laboratory experiments and simulation studies carried out to investigate the effect of mode of injection on oil recovery during CO2-foam flooding of water flooded fractured chalk models at reservoir conditions. The fractured model was created by drilling a hole through the centre of the plug and homogeneously packing it with glass beads. The CO2-foam process was conducted by injecting pre-formed foam either horizontally or vertically into the fractured models at 340 bar and 55°C. Pure CO2 and WAG processes were also carried out on similar fractured models to establish base case behaviours at the same conditions.Laboratory results show that additional oil after water flooding is recoverable by injecting pre-formed foam either horizontally or vertically (from the top) in the CO2-foam processes when compared to the injection of pure CO2 and CO2-WAG at the same effective permeability and CO2 volume. In the simulation studies carried out with CMG's compositional reservoir simulator STARS on a similar fractured model used in the laboratory experiments, the results from the core floods were quantitatively confirmed. Additional simulation carried out in large matrix blocks on the field scale showed that CO2-foam can recover additional oil at reservoir conditions. However, the adsorption of the foaming agent can make the CO2-foam process inefficient.

Many experimental and analytical investigations of the CO2 performance at reservoir conditions have been performed world-wide in the recent years. However integrating many of those findings into reservoir simulation models still remains an open issue. In this manuscript we address only the reservoir aspects of the CO2 injection to Enhance Oil Recovery (EOR) leaving behind transport, metal corrosion and economic issues related to CO2 injection. CO2 is an efficient agent to increase oil recovery, especially, if conditions of oil displacement are miscible. However, CO2"gas like" low viscosity at reservoir conditions may cause severe viscous fingering and displacement front instability resulting in low sweep efficiency. CO2 may boost precipitation of waxes and asphaltenes, thus reducing productivity or completely plugging the wells. CO2, being a chemically active component at reservoir conditions, may provoke chemical reactions and mineralogical changes in situ resulting in increased permeability, loose of sealing properties of the cap rock. Based on the laboratory investigations we aim at building a consistent model to evaluate CO2 injection performance at reservoir conditions. The laboratory studies were conducted in such a way that a single or several natural phenomena were isolated and individually studied. The experimental results allowed us to gain a better knowledge of the process mechanisms. Doing history matching simulations of the experiments we evaluate critical parameters, validate and calibrate numerical models. The complexity of the simulation model is gradually built up from simple experiments to full scale simulation. The mechanisms addressed investigated are: Viscous fingering; Multiphase compositional effects; Flow in naturally fractured porous media (diffusive fluxes and gravity segregation); CO2 dissolution in aqueous phase; Chemical interaction between rock and CO2; CO2 mobility control agents. Special attention in this paper is paid to the viscous effects during CO2 injection at above critical reservoir conditions. The laboratory experiments were performed with different oils. Pure CO2 and CO2 -rich oleic phases were injected to investigate gravitational and viscous effects in the porous medium. It was shown that using relative permeabilities dependant on rate and interfacial tension can improve the accuracy of CO2 injection simulation. Water Alternating Gas (WAG) injection was shown to be an effective way for remediation of viscous fingering. Conclusions on various CO2 injection phenomena and ability of reservoir modelling tools to handle those phenomena are drawn.

This paper addresses simulation aspects of the CO2 injection into the porous media. The presented results are based on the mechanistic and laboratory scale simulations. These findings would lay out the basis for the field scale CO2 injection pilot.

This paper combines the knowledge and experience accumulated at the International Research Institute of Stavanger (IRIS) over a number of years, based on several case studies involving the Tjelbergodden CO2 value chain, modelling of CO2 injection at the Ekofisk field (fractured chalk reservoir) and Gullfaks CO2 injection compositional study. The paper discusses the importance of correctly representing the physical effects when modelling miscible or immiscible CO2 injection in sandstone and carbonate reservoirs. The following aspects were evaluated: Transfer of CO2 from fractures to matrix involving diffusive, gravitational and capillary forces; Viscous effects; Formation of low and high concentration liquid hydrocarbon phases; Compositional effects such as miscible displacement and oil swelling; Chemical interaction between CO2, formation or injection water and reservoir rock. The sensitivity and importance of these effects were studied on several simplified mechanistic models and later applied to actual field cases. An overview of viscous fingering effects is presented. Results from mechanistic studies of the CO2 matrix-fracture transfer are shown and physical effects are discussed. The paper also presenets critical aspects of Equation-Of-State (EOS) modelling and PVT experiments necessary for a CO2 flood simulation study. From our experience we suggest a "cooking recipe" for building reservoir simulation models for CO2 based IOR process evaluations. Case studies of the CO2 and CO2-WAG IOR methods for reservoirs on the Norwegian Continental Shelf (NCS) are presented and oil recovery potentials of these IOR processes are discussed.

Y. Cinar, SPE, and K. Jessen, SPE, Stanford U.; R. Berenblyum, SPE, Technical U. of Denmark; and R. Juanes, SPE,and F.M. Orr Jr., SPE, Stanford U.SummaryIn this paper, we present flow visualization experiments and nu-merical simulations that demonstrate the combined effects of vis-cous and capillary forces and gravity segregation on crossflow thatoccurs in two-phase displacements in layered porous media.We report results of a series of immiscible flooding experi-ments in 2D, two-layered glass bead models. Favorable mobility-ratio imbibition and unfavorable mobility-ratio drainage experi-ments were performed. We used pre-equilibrated immisciblephases from a ternary isooctane/isopropanol/water system, whichallowed control of the interfacial tension (IFT) by varying theisopropanol concentration. Experiments were performed for a widerange of capillary and gravity numbers. The experimental resultsillustrate the transitions from flow dominated by capillary pressureat high IFT to flow dominated by gravity and viscous forces at lowIFT. The experiments also illustrate the complex interplay of cap-illary, gravity, and viscous forces that controls crossflow. Theexperimental results confirm that the transition ranges of scalinggroups suggested by Zhou et al. (1994) are appropriate/valid.We report also results of simulations of the displacement ex-periments by two different numerical techniques: finite-differenceand streamline methods. The numerical simulation results agreewell with experimental observations when gravity and viscousforces were most important. For capillary-dominated flows, thesimulation results are in reasonable agreement with experimen-tal observations.IntroductionStreamline methods are very efficient numerical techniques forfield-scale reservoir simulation, but they are not without limita-tions. They treat flow along each streamline as independent ofadjacent streamlines and therefore do not typically represent cross-flow in the simulations. If users of streamline methods are tointerpret simulation results reliably, they will need to assess wheth-er any of the mechanisms not modeled in the simulations areimportant enough to limit the accuracy of the simulations appreciably.Transfer of fluid in the direction transverse to streamlines canresult from diffusion and dispersion, crossflow caused by viscousand capillary forces, and gravity segregation. The scaling of dif-fusion and dispersion has been investigated in a number of previ-ous studies. If the injected gas is miscible or partially miscible withthe oil, diffusion and dispersion mechanisms may play a signifi-cant role in the displacement (Mohanty and Johnson 1993; Fayersand Lee 1994; Tchelepi 1994; Jiang and Butler 1994; Burger andMohanty 1997). In particular, Burger and Mohanty (1997) showedthat diffusion through the oil phase can limit mass transfer from oilresiding in low-permeability regions. Similar arguments can alsoapply to other mechanisms of crossflow: viscous and capillarycrossflow as well as gravity segregation (Fayers and Lee 1994;Burger and Mohanty 1997; Zapata and Lake 1981; Zhou et al. 1994).Scaling analysis of crossflow mechanisms for displacements inheterogeneous media allows assessment of the relative contribu-tions of each driving force to flow (Tchelepi 1994; Zhou et al.1994; Shook et al. 1992). Starting from material balance equationsand defining them in dimensionless variables, scaling groups canbe obtained that determine the regime of flow during displacement.The relevant scaling groups for displacement of oil by water insystems that contain some simple heterogeneity such as layers arethe transverse gravity and capillary numbers, which are given by(Tchelepi 1994; Zhou et al. 1994)

This paper presents the development of a three-dimensional (3D), three-phase compositional reservoir simulator based on the streamline method and its application to the simulation of water-alternating-gas (WAG) processes. The three-phase compositional streamline simulator has been developed by integrating a one-dimensional (1D) three-phase compositional solver into the 3DSL streamline simulator. 2D and 3D simulations of WAG processes have been performed using the developed simulator. Comparison with the commercial finite difference simulator Eclipse 300 (E300) has also been made. The results from the two simulators are generally in good agreement while the streamline simulator is much faster than E300 and the speed-up factor increases with the simulation size. This study further extends the application area of the streamline method and shows that the streamline technique can be used successfully for displacement processes with complex physics like that encountered in a WAG process.

STRATEGY CCUS is a three-year project (2019-2022) funded by the H2020 research and innovation framework of the European Commission. It comprises 17 partners and is coordinated by BRGM (France). STRATEGY CCUS aims to provide realistic strategic plans from 2025 to 2050 for deploying carbon capture, utilization and storage (CCUS) in Southern and Eastern Europe, from a local to a European scale. Eight promising regions, within seven countries are being studied. Plans and roadmaps for these regions will be developed based on economic and environmental drivers, technical potential and social acceptance. The deployment of operational CCUS clusters starts by an appraisal at local and regional level. Available data for each promising region was mapped to indicate the technical potential of CCUS development in each region. Relevant groups of stakeholders were identified and invited to form Regional Stakeholder Committees within each promising region. These committees are working with project partners to consider regional factors and concerns as well as to elaborate scenarios of CCUS deployment in their respective regions to ensure early local participation. In the 3 most promising regions for the deployment of CCUS, Life Cycle Assessment (LCA), Multiregional Input Output (MRIO) analysis and Techno-Economic Assessment (TEA) designs will provide decision-support for the sustainable development of CCUS. Sound insights and a comprehensive diagnosis of the potential local business models associated with the different CCUS options will be provided for each region, as well as estimates for the sensitivity of the business model on storage capacity and injectivity data. CCUS roadmaps from 2025 to 2050 for each of the promising regions, with optional connections to existing CO2 infrastructure in the North Sea, will be elaborated. Scenarios will be based on the available relevant data and carried out in close exchange with the local stakeholders via the Regional Stakeholder Committees and the Industrial Club. Economic evaluation of each scenario will provide the main Key Performance Indicators (KPIs) such as cumulated CAPEX/OPEX required for each scenario, the cost breakdown per CCUS stakeholder, or for example the global costs expressed in €/t CO2 avoided per scenario. Lastly, an economic impact assessment will be performed at national and European levels in terms of volumes of quotas avoided for industries included in the European Emission Trading Scheme (EU ETS) with the CCUS scenarios and in terms of economic impact on the EU ETS carbon price. Exploitation and dissemination of the project’s results and findings engage with relevant end-users (industry and policy makers, local authorities), in order to pave the way for the operational implementation of CCUS clusters. The project is providing targeted information to multiple audiences (including the media and the public) and favoring dialogue, with a public policy perspective. The systematic approach followed by STRATEGY CCUS will facilitate the appraisal of new other promising regions and the creation of connection among them for the deployment of CCUS Europe-wide.

A streamline simulation with capillary and gravity is presented. The black oil streamline simulator [3DSL 0.25 by R.P. Batycky, SUPRI-C group, Department of Petroleum Engineering, Stanford University, 1997] was modified to incorporate capillary effects. The new simulator has been applied to several simulation cases. We discuss the influence of different factors that may impact performance prediction of water floods. The capillary forces are demonstrated to stabilize the displacement front and increase oil production even in rather viscous-dominated cases. The new approach can provide a fast and a reliable tool for the simulation of water flooding in low permeable and heterogeneous oil reservoirs as well as for reservoir screening and upscaling studies.

The oil and gas industry has accumulated significant experience in carrying out improved/enhanced oil recovery (IOR/EOR) projects. The outcome of different IOR/EOR methods applied to the fields world wide is available in open data sources as well as internal databases of oil companies. Open data typically include general information about oil field, average reservoir and fluid properties (reservoir parameters), and efficiency of an IOR/EOR method applied. Statistical analysis of such data may be applied to evaluate IOR/EOR potential of a particular field. Since such analysis requires small amount of information on a field, it is suitable for screening of large number of fields or evaluation of new discoveries or acquisitions. A new statistical approach to predict efficiency of different IOR/EOR methods for particular reservoir parameters has been developed and tested on actual filed data. The approach utilizes multi-dimensional statistical analysis based on data clustering. The K-means clustering is used to partition a filed case database into clusters based on reservoir parameters. A set of six representative parameters (porosity, permeability, depth and oil density, viscosity and temperature) has been chosen based on parameter correlation studies described in literature. Visualization of the cluster analysis results is performed via projection of six-dimensional vectors into two-dimensional space using the principal component method. IOR/EOR potential for a new field case is evaluated into two steps: (1) association of the case with a nearest cluster utilizing the discriminant analysis and (2) multi-dimensional interpolation of recovery factor for different methods within the cluster. A quality control is carried out at all stages of the statistical analysis to confirm its reliability. A list of potential methods with an estimation of recovery factor classified according to the confidence index (a measure of reliability) is outputted as a result of the analysis performed. Described algorithm was coded and tested on actual field case databases. The tests have shown good quality and reliability of the results obtained at all stages of the analysis. The testing has also revealed that reliable evaluation of IOR/EOR potential is possible for databases containing at least ten field cases with a particular method. Application of the new approach may serve as an IOR/EOR compass when potentially efficient methods have to be identified. A database containing actual field data and/or results of laboratory experiments and reservoir simulations may be used as an input for such analysis.

Summary Well testing and Pressure Transient Analysis (PTA) are generally used for reservoir characterization. Matching analytical models to pressure and its derivative within PTA is similar to history matching in reservoir simulation. The ultimate goal of reservoir simulation is forecast, but forecast capabilities of PTA models are often underestimated. In this paper, we examine forecast capabilities of such models in application to CO2 storage in saline aquifers. Since the simplest way of characterizing aquifers is a short-term water production or injection followed by well shut-in, such a well test is a basis for injection capacity evaluation. Assuming that a reservoir (PTA) model (analytical in the simplest case) can be assembled and matched to such a test, pressure build-up forecast for water injection may be simulated. The main focus of this paper is converting such forecast for water into the CO2 injection case. Using numerical simulations of synthetic and actual field cases, the ability to account for near wellbore CO2 banking in PTA models employing the well skin concept was confirmed. PTA models can provide a first evaluation of potential CO2 storage capacity requiring substantially less resources compared to conventional reservoir simulation. This evaluation may be further improved by full-field reservoir simulation.