Prevention of CO2 leakage from underground storage reservoirs

The risk of leakage from CO2 storage sites is recognised as one of the challenging aspects of large scale implementation of geologic sequestration of CO2. Uncertainties in characterizing a geologic reservoir and the current lack of a complete understanding of possible interactions between rock and fluids involved in CO2 storage have resulted in concerns over contingent leakages. The debate on the allowable rate of leakage has led to different perspectives among the CCS stakeholders; some believe that, by analogy to natural CO2 reservoirs, risk of having leakage of less than 1 %/year is dispensable and on the other side, some state that “Any non-zero leak-rate from a stored carbon system means that eventually the entire inventory will be released to the atmosphere”. There is also the issue of public acceptance which would be adversely affected by the non-zero potential of leakage of CO2 back to the surface. This negative impact on the members of the public has proved to be very powerful as it has resulted in the delay and even cancellation of some CCS (carbon capture and storage) projects. To the best of our knowledge, no practically viable techniques existed for prevention of CO2 leaks from unknown leakage paths. Our technique is based on in-situ precipitation of an appropriate solute dissolved in the stored super-critical CO2. Supercritical CO2 (SCCO2) has a distinct characteristic that its density changes from gaseous-like to liquid like monotonically and uniformly. This allows SCCO2 to act as manageable solvent for various solid solutes. Thus, once the solution of SCCO2 + solid solutes departs from the equilibrium conditions, the solute will appear in the form of crystallized particles. Based on this unique behaviour of the supercritical solutions, we have developed a novel technique for tackling contingent CO2 leakage from storage sites as a preventive method. The sealing process takes place in-situ at the exact location of the leak without the need for identifying the leak target area and the exact nature of the leak. In this study, an integrated research methodology was designed and employed to comprehend the physics behind our leakage prevention technique and also, to deliver the required package, i.e. suitable solutes and reliable simulator, for larger scale implementation of this technique. It was aimed firstly to demonstrate the performance of our proposed leakage prevention technique at different leakage scenarios and secondly, to put forward a number of solutes efficient in tackling contingent leakages. In order to identify the underlying mechanisms and the pertinent parameters controlling the efficacy of this technique, a good number of direct visualisation experiments were performed where the kinetics behind solute solidification and precipitation were visually investigated. Three different ranges of potential solid solutes were used in visualisation experiments to cover a wide spectrum of solute solubility in supercritical CO2, which would enable us to draw more general and consistent conclusions. The understandings acquired from the direct visualisations were employed to design efficiently a few yet adequate number of coreflood experiments in which the performance of our technique was studied in more realistic reservoir cores. Having attained the adequate information from the experimental part of this investigation, the findings was subsequently utilised to develop an in-house simulator to fundamentally model the kinetics of solid solute precipitation and consequently, the pertinent parameters of the semi-empirical equations were tuned to match and predict the coreflood experiments. In experimental part of this investigation, a series of visualisation experiments using transparent porous media (micromodel) to physically simulate CO2 leakage under conditions typical of geologic storage sites. In these experiments, degree of “supersaturation” was identified as an important parameter behind effectiveness of solute precipitation. In addition to evaluating the behaviour of different solutes, the impacts of resident water existing in storage reservoir and impurities in CO2 stream were taken into account in visualisation experiments. Utilising the findings from the visualisations, 6 coreflood experiments were carried out, which revealed that a strong and durable blockage was formed in the core and the flow (leakage) of CO2 was effectively sealed. Practically speaking, there should not be any premature precipitation as the solution travels inside the storage reservoir; therefore, apart from the performance of this technique in the vicinity of contingent leakages, the integrity of the solution (as it flows in the simulated storage reservoir) was also investigated in visualisation and coreflood experiments. From the findings revealed by the coreflood and micromodel experiments, it was identified that the solution made with solid-solute and SCCO2 may not be responsive in some scenarios. Therefore, the desire to better control the onset of blockage formation has triggered investigation of developing a complementary method to be able to adjust the response of the solution. It was rationalised that adding another solutes (co-solvent) to the solution would enable us to modify the response of the solution. Sandpack, micromodel visualisations, and coreflood experiments were performed to evaluate influence of co-solvent on the response of the solution to various leakage types. On the modelling the precipitation process in the leakage path, it was first demonstrated that conventional reservoir simulators could not adequately capture the physics leading to the blockage formation and the results of lab-scale coreflood experiments could not be correctly simulated. Therefore, there is a need for developing models, which can predict the performance of the LPT at different cases. Based on the experimental information, we have attempted to develop the relevant equations that describe the mechanisms behind particle formation due to pressure drops. After matching one coreflood experiment, the resultant model was used to predict another coreflood experiment performed at similar conditions, which demonstrated an encouraging performance for the developed mathematical model. The results and findings of this study have primarily verified that our leakage prevention technique, which is developed here through extensive experimental and modelling investigation, is well-capable of tackling various contingent leakages. A number of economically feasible solid solute has been found with positive responses to physically simulated leakage paths, which would be considered as the potential solutes for large scale implementation of our technique. Moreover, an in-house simulator was developed based on the finding observed in the different experiments. The simulator can successfully predict the results of coreflood experiments, which implies that it captures the underlying mechanisms adequately. Having developed the necessary equipment, i.e. appropriate solutes and reliable simulator, our proposed leakage prevention technique is ready to be incorporated in demonstration and pilot trials

A robust methodology to simulate water-alternating-gas experiments at different scenarios under near-miscible conditions

Three-phase flow in porous media during water-alternating-gas (WAG) injections and the associated cycle-dependent hysteresis have been subject of studies experimentally and theoretically. In spite of attempts to develop models and simulation methods for WAG injections and three-phase flow, current lack of a solid approach to handle hysteresis effects in simulating WAG-injection scenarios has resulted in misinterpretations of simulation outcomes in laboratory and field scales. In this work, by use of our improved methodology, the first cycle of the WAG experiments (first waterflood and the subsequent gasflood) was history matched to estimate the two-phase krs (oil/water and gas/oil). For subsequent cycles, pertinent parameters of the WAG hysteresis model are included in the automatic-history-matching process to reproduce all WAG cycles together. The results indicate that history matching the whole WAG experiment would lead to a significantly improved simulation outcome, which highlights the importance of two elements in evaluating WAG experiments: inclusion of the full WAG experiments in history matching and use of a more-representative set of two-phase krs, which was originated from our new methodology to estimate two-phase krs from the first cycle of a WAG experiment. Because WAG-related parameters should be able to model any three-phase flow irrespective of WAG scenarios, in another exercise, the tuned parameters obtained from a WAG experiment (starting with water) were used in a similar coreflood test (WAG starting with gas) to assess predictive capability for simulating three-phase flow in porous media. After identifying shortcomings of existing models, an improved methodology was used to history match multiple coreflood experiments simultaneously to estimate parameters that can reasonably capture processes taking place in WAG at different scenarios--that is, starting with water or gas. The comprehensive simulation study performed here would shed some light on a consolidated methodology to estimate saturation functions that can simulate WAG injections at different scenarios

Crude oil/brine interactions and spontaneous formation of microdispersions in low salinity water injection

AbstractLow salinity water injection (LSW) has recently attracted much attention as a technique for improving oil recovery. Several mechanisms have been put forward for oil recovery by LSW, however, their contribution to the observed additional oil recovery has not been well established and currently a consistent mechanism that can adequately explain both successful and unsuccessful results of LSW is lacking. Most of the proposed mechanisms attribute the low salinity effects to wettability alteration towards more water-wet conditions. This has resulted in many studies of LSW being mainly focused on the role of rock and its constituents whereas the role of fluid/fluid interactions has been largely ignored. We have recently reported the results of a series of direct flow visualization of LSW, which have revealed spontaneous formation of micro-dispersions of water in oil when a crude oil comes in contact with low salinity brines (Emadi and Sohrabi 2013).In the current work, we further investigated interactions between crude oil and brine by performing a series of fluid characterization tests. Five different crude oil samples were used to individually bring them in contact with brines with various salinity levels to identify experimentally subtle changes in the oil composition. The process of contacting the crude oils and brines was designed and performed very carefully to avoid physical agitation between the two phases in order to replicate reservoir flow conditions. Then, samples of the oil were taken for qualitative and quantitative analysis including ESEM, FTIR, and Karl Fischer Titration. The results demonstrate spontaneous formation of water-in-oil dispersions when salinity of the brine is reduced to below 2000 ppm. This phenomenon is associated with detectable changes in oil composition, which occurred consistently in the tested crude oils. Our quantitative analysis shows that the concentration of micro-dispersions varies depending on the SARA content of the oil and there is a brine salinity threshold at which microdispersion concentration in the oil changes sharply. These new findings coupled with our micromodel visualizations (Emadi &amp; Sohrabi 2013) reveal some new aspects of LSW and may lead to the development of relatively simple screening tests to identify suitability of a crude oil for LSW.</jats:p

Best Practices for Shale Core Handling: Transportation, Sampling and Storage for Conduction of Analyses

Drill core shale samples are critical for palaeoenvironmental studies and potential hydrocarbon reservoirs. They need to be preserved carefully to maximise their retention of reservoir condition properties. However, they are susceptible to alteration due to cooling and depressurisation during retrieval to the surface, resulting in volume expansion and formation of desiccation and micro fractures. This leads to inconsistent measurements of different critical attributes, such as porosity and permeability. Best practices for core handling start during retrieval while extracting from the barrel, followed by correct procedures for transportation and storage. Appropriate preservation measures should be adopted depending on the objectives of the scientific investigation and core coherency, with respect to consolidation and weathering. It is particularly desirable to maintain a constant temperature of 1 to 4 &deg;C and a consistent relative humidity of &gt;75% to minimise any micro fracturing and internal moisture movement in the core. While core re-sampling, it should be ensured that there is no further core compaction, especially while using a hand corer

A Fundamental Micro Scale Study of the Roles of Associated Gas Content and Different Classes of Hydrocarbons on the Dominant Oil Recovery Mechanism by CWI

Abstract Various studies demonstrated new gaseous phase formation and oil swelling and viscosity reduction are the oil recovery mechanisms by carbonated water injection (CWI) with new gaseous phase formation being the major recovery mechanism for live oil systems. However, none of the previous studies investigated the influences of dissolved gas content of the oil and oil composition, on the new gaseous phase. This study attempts to provide insights on this area. Based on the results, during CWI as CO2 partitions into the oil the dissolved gas of the oil liberates, which leads to in-situ new gaseous phase formation. The dissolved gas content of the crude oil has a direct impact on the saturation and growth rate of the new gaseous phase. The new gaseous phase doesn’t form for oils that have an infinite capacity for dissolving CO2, such as light pure hydrocarbon components. Oils with limited capacity for dissolving CO2, such as heavy hydrocarbon components, are responsible for the formation of the new gaseous phase. Therefore for a live crude oil, the relatively heavier fractions of oil are responsible for triggering of the new gaseous phase and light to intermediate oil components control the further growth of the new gaseous phase

Co-history Matching:A Way Forward for Estimating Representative Saturation Functions

Core-scale experiments and analyses would often lead to estimation of saturation functions (relative permeability and capillary pressure). However, despite previous attempts on developing analytical and numerical methods, the estimated flow functions may not be representative of coreflood experiments when it comes to predicting similar experiments due to non-uniqueness issues of inverse problems. In this work, a novel approach was developed for estimation of relative permeability and capillary pressure simultaneously using the results of “multiple” corefloods together, which is called “co-history matching.” To examine this methodology, a synthetic (numerical) model was considered using core properties obtained from pore network model. The outcome was satisfactorily similar to original saturation functions. Also, two real coreflood experiments were performed where water at high and low rates were injected under reservoir conditions (live fluid systems) using a carbonate reservoir core. The results indicated that the profiles of oil recovery and differential pressure (dP) would be significantly affected by injection rate scenarios in non-water wet systems. The outcome of co-history matching could indicate that, one set of relative permeability and capillary pressure curves can reproduce the experimental data for all corefloods

Impact of in-situ gas liberation for enhanced oil recovery and CO 2 storage in liquid-rich shale reservoirs

International audienceCarbon dioxide injection in shale reservoirs can be beneficial for enhanced oil recovery and CO2 storage scenarios. CO2 mass transfer can be influenced strongly by the in-situ liberation of light oil components from live oil forming a distinct gas phase. This mechanism has been overlooked in the past for studying CO2 and oil interactions in tight formations. In this work, a series of analytical solutions and numerical simulations were developed to identify the effect on EOR by CO2 due to the liberation of a light hydrocarbon gas phase from live oil in shales. The analytical model demonstrated faster diffusion of CO2 in the two-phase system due to the presence of this gas phase. Using numerical approaches, laboratoryscale simulations indicated that in-situ gas formation can increase oil recovery by 35%. At the field-scale, an additional oil recovery of 9.8% could be attained. Also, the CO2 storage capacity of shale formations could be significantly enhanced due to capillary trapping of CO2 in the liberated gas. The results of this study could potentially be used to improve evaluations of the potential of CO2 EOR in shale reservoirs