Role of fault and fracture networks to de-risk geological leakage from subsurface energy sites

2021 ◽  
Author(s):  
Roberto Emanuele Rizzo ◽  
Hossein Fazeli ◽  
Florian Doster ◽  
Niko Kampman ◽  
Kevin Bisdom ◽  
...  
Keyword(s):  
Carbon Capture ◽  
Fracture Stress ◽  
Effective Permeability ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Fracture Network ◽  
Natural Fracture ◽  
Single Fracture ◽  
Fracture Networks ◽  
Geological Co2 Storage

<p>The success of geological carbon capture and storage projects depends on the integrity of the top seal, confining injected CO<sub>2</sub> in the subsurface for long periods of time. Here, faults and related fracture networks can compromise sealing by providing an interconnected pathway for injected fluids to reach overlying aquifers or even the surface or sea bottom. In this work, we apply an integrated workflow [1] that, combining single fracture stress-permeability laboratory measurements and detailed fault and fracture network outcrop data, builds permeability models of naturally faulted caprock formations for in situ stress conditions.</p><p>We focus our study on two-dimensional (2D) fault-related fracturing within caprock sequences cut by extensional faults. 2D data of fault and fracture networks were collected from an Upper Jurassic to Lower Cretaceous shale-dominated succession in the Konusdalen area (Nordenskioldland, Svalbard, Norway). The studied rock succession represents the regional caprock and seal for the reservoir of the nearby Longyearbyen CO<sub>2</sub> Lab. By digitising all the visible features over the images and then inputting them into the open-source toolbox FracPaQ [2], we obtain information about the fault and fracture networks. In particular, we study the variations in fracture size (i.e., length, height) and density distribution near and away from the fault zone(s), together with the connectivity of fractures within the network. These three parameters are fundamental to establish if the network provides permeable pathways. They also enable us to statistically reproduce and upscale a fracture network in a realistic way.</p><p>Combining laboratory single fracture stress-permeability measurements with outcrop fracture network data allow us to create an accurate coupled mechanical-hydromechanical model of the natural fracture network and to evaluate the effective permeability of a fault related fracture network. These results are also compared against analytical estimates of effective permeability [3]. With this workflow, we overcome the geometrical simplifications of synthetic fracture models, thus allowing us to establish representative stress-permeability relationships for fractured seals of geological CO2 storage.</p><p>Reference: [1] March et al., 2020, Preprint; [2] Healy et al., 2017, JSG; [3] Seavik & Nixon, 2017, WRR</p>

scholarly journals The potential for large-scale, subsurface geological CO2 storage in Denmark

1969 ◽  
Vol 17 ◽  
pp. 13-16 ◽  
Author(s):  
Peter Frykman ◽  
Lars Henrik Nielsen ◽  
Thomas Vangkilde-Pedersen
Keyword(s):  
Carbon Capture ◽  
Large Scale ◽  
Best Practice ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
The European Union ◽  
Geological Storage ◽  
Geological Co2 Storage ◽  
Research Programmes ◽  
Capture Techniques

Carbon capture and storage (CCS) is increasingly considered to be a tool that can significantly reduce the emission of CO2. It is viewed as a technology that can contribute to a substantial, global reduction of emitted CO2 within the timeframe that seems available for mitigating the effects of present and continued emission. In order to develop the CCS method the European Union (EU) has supported research programmes for more than a decade, which focus on capture techniques, transport and geological storage. The results of the numerous research projects on geological storage are summarised in a comprehensive best practice manual outlining guidelines for storage in saline aquifers (Chadwick et al. 2008). A detailed directive for geological storage is under implementation (European Commission 2009), and the EU has furthermore established a programme for supporting the development of more than ten large-scale demonstration plants throughout Europe. Geological investigations show that suitable storage sites are present in most European countries. In Denmark initial investigations conducted by the Geological Survey of Denmark and Greenland and private companies indicate that there is significant storage potential at several locations in the subsurface.

scholarly journals Chemistry of Reservoir Fluids in the Aspect of CO2 Injection for Selected Oil Reservoirs in Poland

Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6456
Author(s):  
Ewa Knapik ◽  
Katarzyna Chruszcz-Lipska
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Oil Reservoirs ◽  
Co2 Injection ◽  
Oil Composition ◽  
Co2 Solubility ◽  
Geological Co2 Storage ◽  
Reservoir Conditions

Worldwide experiences related to geological CO2 storage show that the process of the injection of carbon dioxide into depleted oil reservoirs (CCS-EOR, Carbon Capture and Storage—Enhanced Oil Recovery) is highly profitable. The injection of CO2 will allow an increasing recovery factor (thus increasing CCS process profitability) and revitalize mature reservoirs, which may lead to oil spills due to pressure buildups. In Poland, such a solution has not yet been implemented in the industry. This work provides additional data for analysis of the possibility of the CCS-EOR method’s implementation for three potential clusters of Polish oil reservoirs located at a short distance one from another. The aim of the work was to examine the properties of reservoir fluids for these selected oil reservoirs in order to assure a better understanding of the physicochemical phenomena that accompany the gas injection process. The chemical composition of oils was determined by gas chromatography. All tested oils represent a medium black oil type with the density ranging from 795 to 843 g/L and the viscosity at 313 K, varying from 1.95 to 5.04 mm/s. The content of heavier components C25+ is up to 17 wt. %. CO2–oil MMP (Minimum Miscibility Pressure) was calculated in a CHEMCAD simulator using the Soave–Redlich–Kwong equation of state (SRK EoS). The oil composition was defined as a mixture of n-alkanes. Relatively low MMP values (ca. 8.3 MPa for all tested oils at 313 K) indicate a high potential of the EOR method, and make this geological CO2 storage form more attractive to the industry. For reservoir brines, the content of the main ions was experimentally measured and CO2 solubility under reservoir conditions was calculated. The reservoir brines showed a significant variation in properties with total dissolved solids contents varying from 17.5 to 378 g/L. CO2 solubility in brines depends on reservoir conditions and brine chemistry. The highest calculated CO2 solubility is 1.79 mol/kg, which suggest possible CO2 storage in aquifers.

CO2 Underground Storage and Wellbore Integrity

2014 ◽  
pp. 322-357 ◽  
Author(s):  
Nediljka Gaurina-Medjimurec ◽  
Borivoje Pasic
Keyword(s):  
Carbon Capture ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Injection Wells ◽  
Geological Co2 Storage ◽  
Wellbore Integrity ◽  
Geologic Storage ◽  
Injection Zone ◽  
Carbon Dioxide Co2 ◽  
Confining Unit

Geologic storage is the component of Carbon Capture and Storage (CCS) in which the carbon dioxide (CO2) is disposed in the appropriate underground formation. To successfully inject CO2 into the subsurface to mitigate greenhouse gases in the atmosphere, the CO2 must to be trapped in the subsurface and must not be allowed to leak to the surface or to potable water sources above the injection zone. For the purposes of risk assessment, a priority is to evaluate what would happen if CO2 migrated unexpectedly through the confining unit(s), potentially resulting in undesirable impacts on a variety of potential receptors. One of the main risks identified in geological CO2 storage is the potential for CO2 leakage through or along wells. To avoid leakage from the injection wells, the integrity of the wells must be maintained during the injection period and for as long as free CO2 exists in the injection zone.

Microfluidic salt precipitation: implications for geological CO2 storage

Lab on a Chip ◽  
2020 ◽  
Vol 20 (20) ◽  
pp. 3806-3814
Author(s):  
Tsai-Hsing Martin Ho ◽  
Peichun Amy Tsai
Keyword(s):  
Carbon Capture ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Salt Precipitation ◽  
Geological Co2 Storage ◽  
Drying Rates ◽  
And Storage ◽  
Storage Processes

Novel microfluidic visualizations reveal the simultaneous dynamics of salt nucleation and fluid drying rates while mimicking carbon capture and storage processes.

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

2013 ◽  
Author(s):  
Hannes Hofmann ◽  
Tayfun Babadagli ◽  
Günter Zimmermann
Keyword(s):  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Network Development ◽  
Complex Fracture ◽  
Fracture Patterns ◽  
Fracture Systems ◽  
Fracture Development ◽  
Complex Fracture Network ◽  
Treatment Designs

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and Hot-Dry-Rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in bi-wing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial Discrete Fracture Network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulation results reveal valuable information about main parameters influencing fracture network properties, major factors leading to complex fracture network development, and differences between HDR and shale gas/oil shale stimulations.

scholarly journals Managing Uncertainty in Geological CO2 Storage Using Bayesian Evidential Learning

Energies ◽  
2021 ◽  
Vol 14 (6) ◽  
pp. 1557
Author(s):  
Amine Tadjer ◽  
Reidar B. Bratvold
Keyword(s):  
Uncertainty Quantification ◽  
History Matching ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Monitoring Program ◽  
Co2 Injection ◽  
Drinking Water Contamination ◽  
Model Inversion ◽  
Geological Co2 Storage ◽  
And Storage

Carbon capture and storage (CCS) has been increasingly looking like a promising strategy to reduce CO2 emissions and meet the Paris agreement’s climate target. To ensure that CCS is safe and successful, an efficient monitoring program that will prevent storage reservoir leakage and drinking water contamination in groundwater aquifers must be implemented. However, geologic CO2 sequestration (GCS) sites are not completely certain about the geological properties, which makes it difficult to predict the behavior of the injected gases, CO2 brine leakage rates through wellbores, and CO2 plume migration. Significant effort is required to observe how CO2 behaves in reservoirs. A key question is: Will the CO2 injection and storage behave as expected, and can we anticipate leakages? History matching of reservoir models can mitigate uncertainty towards a predictive strategy. It could prove challenging to develop a set of history matching models that preserve geological realism. A new Bayesian evidential learning (BEL) protocol for uncertainty quantification was released through literature, as an alternative to the model-space inversion in the history-matching approach. Consequently, an ensemble of previous geological models was developed using a prior distribution’s Monte Carlo simulation, followed by direct forecasting (DF) for joint uncertainty quantification. The goal of this work is to use prior models to identify a statistical relationship between data prediction, ensemble models, and data variables, without any explicit model inversion. The paper also introduces a new DF implementation using an ensemble smoother and shows that the new implementation can make the computation more robust than the standard method. The Utsira saline aquifer west of Norway is used to exemplify BEL’s ability to predict the CO2 mass and leakages and improve decision support regarding CO2 storage projects.

A Sensitivity Analysis for Effective Parameters on 2D Fracture-Network Permeability

2009 ◽  
Vol 12 (03) ◽  
pp. 455-469 ◽  
Author(s):  
Alireza Jafari ◽  
Tayfun Babadagli
Keyword(s):  
Sensitivity Analysis ◽  
Experimental Design ◽  
Fractured Reservoirs ◽  
Fracture Network ◽  
Static Model ◽  
Naturally Fractured Reservoirs ◽  
Single Fracture ◽  
Data Sets ◽  
Fracture Networks ◽  
Fractal Characteristics

Summary Fracture-network mapping and estimation of its permeability constitute two major steps in static-model preparation of naturally fractured reservoirs. Although several different analytical methods were proposed in the past for calculating fracture-network permeability (FNP), different approaches are still needed for practical use. We propose a new and practical approach to estimate FNP using statistical and fractal characteristics of fracture networks. We also provide a detailed sensitivity analysis to determine the relative importance of fracture-network parameters on the FNP in comparison to single-fracture conductivity using an experimental-design approach. The FNP is controlled by many different fracture-network parameters such as fracture length, density, orientation, aperture, and single-fracture connectivity. Five different 2D fracture data sets were generated for random and systematic orientations. In each data set, 20 different combinations of fracture density and length for different orientations were tested. For each combination, 10 different realizations were generated. The length was considered as constant and variable. This yielded a total of 1,000 trials. The FNPs were computed through a commercial discrete-fracture-network (DFN) modeling simulator for all cases. Then, we correlated different statistical and fractal characteristics of the networks to the measured FNPs using multivariable-regression analysis. Twelve fractal (sandbox, box counting, and scanline fractal dimensions) and statistical (average length, density, orientation, and connectivity index) parameters were tested against the measured FNP for synthetically generated fracture networks for a wide range of fracture properties. All cases were above the percolation threshold to obtain a percolating network, and the matrix effect was neglected. The correlation obtained through this analysis using four data sets was tested on the fifth one with known permeability for verification. High-quality match was obtained. Finally, we adopted an experimental-design approach to identify the most-critical parameters on the FNP for different fracture-network types. The results are presented as Pareto charts. It is believed that the new method and results presented in this paper will be useful for practitioners in static-model development of naturally fractured reservoirs and will shed light on further studies on modeling and understanding the transmissibility characteristics of fracture networks. It should be emphasized that this study was conducted on 2D fracture networks and could be extended to 3D models. This, however, requires further algorithm development to use 2D fractal characteristics for 3D systems and/or development of fractal measurement techniques for a 3D system. This study will provide a guideline for this type of research.

scholarly journals Valorization of OFMSW Digestate-Derived Syngas toward Methanol, Hydrogen, or Electricity: Process Simulation and Carbon Footprint Calculation

Processes ◽  
2020 ◽  
Vol 8 (5) ◽  
pp. 526 ◽  
Author(s):  
Aristide Giuliano ◽  
Enrico Catizzone ◽  
Cesare Freda ◽  
Giacinto Cornacchia
Keyword(s):  
Hydrogen Production ◽  
Process Simulation ◽  
Carbon Capture ◽  
Combustion Engine ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Simulation Software ◽  
Added Value ◽  
Electricity Production ◽  
Methanol Production

This paper explores a possible waste-based economy transition strategy. Digestate from the organic fraction of municipal solid waste (OFMSW) is considered, as well as a low-added value product to be properly valorized. In this regard, air gasification may be used to produce syngas. In this work, the production of methanol, hydrogen, or electricity from digestate-derived syngas was assessed by ChemCAD process simulation software. The process scheme of methanol production comprises the following parts: water gas shift (WGS) with carbon capture and storage units (CCS), methanol synthesis, and methanol purification. In the case of hydrogen production, after WGS-CCS, hydrogen was purified from residual nitrogen by pressure swing absorption (PSA). Finally, for electricity production, the digestate-derived syngas was used as fuel in an internal combustion engine. The main objective of this work is to compare the proposed scenarios in terms of CO2 emission intensity and the effect of CO2 storage. In particular, CCS units were used for methanol or hydrogen production with the aim of obtaining high equilibrium yield toward these products. On the basis of 100 kt/year of digestate, results show that the global CO2 savings were 80, 71, and 69 ktCO2eq/year for electricity, methanol, and hydrogen production, respectively. If carbon storage was considered, savings of about 105 and 99 ktCO2eq/year were achieved with methanol and hydrogen production, respectively. The proposed scenarios may provide an attractive option for transitioning into methanol or hydrogen economy of the future.

scholarly journals The Endurance CO2 storage site, Blocks 42/25 and 43/21, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 163-171 ◽  
Author(s):  
Jon G. Gluyas ◽  
Usman Bagudu
Keyword(s):  
Carbon Capture ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Lower Triassic ◽  
Injection Rate ◽  
Government Support ◽  
Storage Site ◽  
Sandstone Formation ◽  
The Uk ◽  
And Storage

AbstractThe Endurance, four-way, dip-closed structure in UK Blocks 42/25 and 43/21 occurs over a salt swell diapir and within Triassic and younger strata. The Lower Triassic Bunter Sandstone Formation reservoir within the structure was tested twice for natural gas (in 1970 and 1990) but both wells were dry. The reservoir is both thick and high quality and, as such, an excellent candidate site for subsurface CO2 storage.In 2013 a consortium led by National Grid Carbon drilled an appraisal well on the structure and undertook an injection test ahead of a planned development of Endurance as the first bespoke storage site on the UK Continental Shelf with an expected injection rate of 2.68 × 106 t of dense phase CO2 each year for 20 years. The site was not developed following the UK Government's removal of financial support for carbon capture and storage (CCS) demonstration projects, but it is hoped with the recent March 2020 Budget that government support for CCS may now be back on track.

Modelling large-scale fractured reservoirs efficiently for geothermal energy and groundwater flow

2020 ◽  
Author(s):  
Simon Oldfield ◽  
Mikael Lüthje ◽  
Michael Welch ◽  
Florian Smit
Keyword(s):  
Fluid Flow ◽  
Geothermal Energy ◽  
Large Scale ◽  
Fractured Reservoirs ◽  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Persistent Problem ◽  
Fracture Evolution ◽  
Rapid Generation

<p>Large scale modelling of fractured reservoirs is a persistent problem in representing fluid flow in the subsurface. Considering a geothermal energy prospect beneath the Drenthe Aa area, we demonstrate application of a recently developed approach to efficiently predict fracture network geometry across an area of several square kilometres.</p><p>Using a strain based method to mechanically model fracture nucleation and propagation, we generate a discretely modelled fracture network consisting of individual failure planes, opening parallel and perpendicular to the orientation of maximum and minimum strain. Fracture orientation, length and interactions vary following expected trends, forming a connected fracture network featuring population statistics and size distributions comparable to outcrop examples.</p><p>Modelled fracture networks appear visually similar to natural fracture networks with spatial variation in fracture clustering and the dominance of major and minor fracture trends.</p><p>Using a network topology approach, we demonstrate that the predicted fracture network shares greater geometric similarity with natural networks. Considering fluid flow through the model, we demonstrate that hydraulic conductivity and flow anisotropy are strongly dependent on the geometric connection of fracture sets.</p><p>Modelling fracture evolution mechanically allows improved representation of geometric aspects of fracture networks to which fluid flow is particularly sensitive. This method enables rapid generation of discretely modelled fractures over large areas and extraction of suitable summary statistics for reservoir simulation. Visual similarity of the output models improves our ability to compare between our model and natural analogues to consider model validation.</p>

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