Subseismic faults are small faults or fractures that may be difficult to determine but can have large consequences for fluid flow and pressure communication in the subsurface. Thus, knowing their distributions may be important in several subsurface applications, such as hydrocarbon exploration and exploitation, geothermal energy production, and subsurface CO2 injection. The aim of this work is to use a stochastic model to populate a three-dimensional structural model of the subsurface with subseismic faults. The novelty of the proposed method is the conditioning of the stochastic model to input maps describing displacement and stress orientation along subsurface horizons. Hence, the resulting structural model will be consistent with these maps. The maps can originate from a variety of sources, for example, predictions of a geomechanical model or (indirect) measurements of subsurface displacements and stresses. The model uses simulated annealing as the optimization algorithm, where the residual between the displacement of the modeled subseismic faults and the input displacement map is minimized through an iterative process. Each subseismic fault is modeled with a three-dimensional displacement field around the fault slip plane, enabling comparisons with the input displacement map along a horizon. An example of how the model distributes the subseismic faults around larger known faults, using a synthetically created displacement map, is provided. The result shows that the model quickly converges towards a set of subseismic faults, giving total displacement and strike orientation close to the input maps.

Pre-drill pore pressure prediction is essential for safe and efficient drilling, and is a key element in the risk-reducing toolbox when designing a well. On the Norwegian Continental Shelf, pore pressure prediction commonly relies on traditional 1D offset well analysis, whereas velocity data from seismic surveys are often not considered. Our work with seismic interval velocities shows that the velocity field can provide an important basis for pressure prediction and enable the construction of regional 3D pressure cubes. This may increase the confidence in the pore pressure models and aid the pre-drill geohazard screening process. We demonstrate how a 3D velocity field can be converted to a 3D pore pressure cube using reported pressures in offset wells as calibration points. The method is applied to a regional dataset at the Halten Terrace in the Norwegian Sea; an area with a complex pattern of pore pressure anomalies which traditionally has been difficult to predict. The algorithm is searching for a velocity to pore pressure transform that best matches the reported pressures. The 3D velocity field is a proxy of rock velocity and is derived from seismic surveys, and is verified to checkshot velocities and sonic data in the offset wells.

We have developed an efficient methodology for Bayesian prediction of lithology and pore fluid, and layer-bounding horizons, in which we include and use spatial geologic prior knowledge such as vertical ordering of stratigraphic layers, possible lithologies and fluids within each stratigraphic layer, and layer thicknesses. The solution includes probabilities for lithologies and fluids and horizons and their associated uncertainties. The computational cost related to the inversion of large-scale, spatially coupled models is a severe challenge. Our approach is to evaluate all possible lithology and fluid configurations within a local neighborhood around each sample point and combine these into a consistent result for the complete trace. We use a one-step nonstationary Markov prior model for lithology and fluid probabilities. This enables prediction of horizon times, which we couple laterally to decrease the uncertainty. We have tested the algorithm on a synthetic case, in which we compare the inverted lithology and fluid probabilities to results from other algorithms. We have also run the algorithm on a real case, in which we find that we can make high-resolution predictions of horizons, even for horizons within tuning distance from each other. The methodology gives accurate predictions and has a performance making it suitable for full-field inversions.

We present results from microseismic monitoring and geomechanical analysis obtained at the industrial-scale CO2 sequestration site at the In Salah gas development project in Algeria. More than 5000 microseismic events have been detected at a pilot monitoring well using a master event cross-correlation method. The microseismic activity occurs in four distinct clusters and thereof three clearly correlate with injection rates and wellhead pressures. These event clusters are consistent with a location within the reservoir interval. However, due to insufficient network geometry there are large uncertainties on event location. We estimate a fracture pressure of 155 bar (at the wellhead) from the comparison of injection pressure and injection rate and conclude that reservoir fracture pressure of the injection horizon has most likely been exceeded occasionally, accompanied by increased microseismic activity. Our analysis of 3-D ray tracing for direct and converted phases suggests that one of the event clusters is located at a shallower depth than the reservoir injection interval. However, this event cluster is most likely unrelated to changes in the injection activity at a single well, as the event times do not correlate with the wellhead pressures. Furthermore, this event cluster shows b-values close to one, indicating re-activated natural or tectonic seismicity on pre-existing weakness zones rather than injection induced seismicity. Analysis of event azimuths and significant shear wave splitting of up to 5 per cent provide further valuable insight into fluid migration and fracture orientation at the reservoir level. Although only one geophone was available during the critical injection period, the microseismic monitoring of CO2 injection at In Salah is capable of addressing some of the most relevant questions about fluid migration and reservoir integrity. An improved monitoring array with larger aperture and higher sensitivity is highly recommended, as it could greatly enhance the value of this technique. As such, real-time microseismic monitoring can be used to guide the injection pressure below fracture pressure, thus providing a tool to mitigate the risk of inducing felt seismicity and compromising seal integrity.

We study acoustic emissions (AEs) associated with shear and tensile failures around a horizontal borehole in a sandstone sample subjected to triaxial stress. The aim is to relate the AE event rate to macroscopic observations of sample deformation and the percentage of isotropic and deviatoric components of the seismic moment tensors to the expected failure mechanisms. The horizontal hole interferes with the applied load and forms a strongly spatially dependent anisotropic stress field, focusing the crack initiation into both shear and tensile failures. The recorded AEs follows reasonably well existing damage models, but the elastic solution of hoop stress does not represent the onset of failure around the borehole. The focal mechanisms correlate with the orientation of macroscopic fractures in the sample. Events close to the borehole show a higher fraction of isotropic percentage in moment tensors compared to events occurring in the macroscopic fracture featuring higher double-couple percentages. The inhomogeneous stress field due to the borehole and the stress induced damage is strongly affecting the axial and radial velocities which in turn affect the waveforms of the recorded AEs and the resulting moment tensors. The VP/VS ratio obtained from the ratio of isotropic to compensated linear vector dipole components of the moment tensors is close to that obtained from ultrasonic velocity measurements.

Microseismic data analysis together with interpretation of injection data at the In Salah CO2 storage site provides a valuable tool for improved understanding of the subsurface injection and storage processes. More than 1500 microseismic events have been detected semi-automatically between August 2009 and May 2012 and the occurrence of the events correlates clearly with increased injection rates and well-head pressures. Most likely the fracture pressure has been exceeded temporarily, resulting in a sudden increase of microseismicity. Waveform cross- correlation of the events demonstrates that most events occur in three distinct clusters. Clusters with shorter S-P wave differential travel times clearly correlate with the CO2 injection at KB502, whereas events with larger S-P wave times do not. An uncertainty analysis and a network design study conclude that a more extensive microseismic network would be needed to resolve locations and potential correlations with injection data.

ABSTRACTThe effect of sub‐core scale heterogeneity on fluid distribution pattern, and the electrical and acoustic properties of a typical reservoir rock was studied by performing drainage and imbibition flooding tests with CO2 and brine in a laboratory. Moderately layered Rothbach sandstone was used as a test specimen. Two core samples were drilled; one perpendicular and the other parallel to the layering to allow injection of fluids along and normal to the bedding plane. During the test 3D images of fluid distribution and saturation levels were mapped by an industrial X‐ray CT‐scanner together with simultaneous measurement of electrical resistivity, ultrasonic velocities as well as amplitudes.The results showed how the layering and the flooding direction influenced the fluid distribution pattern and the saturation level of the fluids. For a given fluid saturation level, the measured changes in the acoustic and electrical parameters were affected by both the fluid distribution pattern and the layering orientation relative to the measurement direction. The P‐wave amplitude and the electrical resistivity were more sensitive to small changes in the fluid distribution patterns than the P‐wave velocity. The change in amplitude was the most affected by the orientation of the layering and the resulting fluid distribution patterns. In some instances the change due to the fluid distribution pattern was higher than the variation caused by the change in CO2 saturation. As a result the Gassmann relation based on ‘uniform' or ‘patchy' saturation pattern was not suitable to predict the P‐wave velocity variation. Overall, the results demonstrate the importance of core‐imaging to improve our understanding of fluid distribution patterns and the associated effects on measured rock‐physics properties.

The controlled-source electromagnetic (CSEM) method is a proven and promising geophysical technique in the hydrocarbon exploration area. Recently, there is increasing interest in applying it to CO2-injection monitoring in both land and marine environments. For example, a marine CSEM survey has been carried out in the Sleipner area in 2008 to map the CO2 plume in the Utsira formation. There are still scientific and technical issues to resolve and improve further. In the current study, we focus on two particular issues. The first is to explore the possibility of modeling the CO2 plume in the Utsira formation at the Sleipner area by means of an effective anisotropic resistivity layer. The second is the application of so-called surface-to-borehole CSEM in order to increase the sensitivity of CSEM data to the CO2 plume.

A field laboratory for monitoring CO2 migration has been established in the Holocene deposit of the Svelvik ridge, located at the sill of the Drammensfjord 50km south of Oslo. Initial characterization of the site shows that the formation is very suitable for studying migration and associated leakage, particularly within the top 50 m where the sediments consist of relatively homogenous sand. In the deeper part of the deposit, the formation seems to have more structure possibly enabling monitoring of horizontal migration and more complex migration patterns.

Supercritical CO2 breakthrough and flow mechanisms in shale have been investigated in laboratory experiments using a high pressure flow cell and cylindrical samples of shale from the Draupne formation in the North Sea. The main objective is to study the basic mechanisms involved in the breakthrough process and define the controlling parameters for supercritical CO2 flow in a low permeable shale.Experimental testing provides new insight into the CO2 breakthrough process through simultaneous measurements of deformation and ultrasonic velocities in the sample. A marked sample dilation associated with the CO2 breakthrough is identified accompanied with a pronounced drop in ultrasonic velocities. X-ray images of the sample using a high resolution 3D computer tomography (CT) scanner provide information on macroscopic fracture distribution inside the sample before and after testing.The CO2 breakthrough pressure for the Draupne material seems to depend on confining pressure and effective pressure rather than pore pressure difference across the sample. After breakthrough the effective CO2 permeability was found to follow a simple model for permeability in fractured rock. The drop in ultrasonic velocity was associated with mechanical changes and possible micro fracturing inside the sample. Based on our observations we conclude that pressure-induced opening of micro-fractures during the breakthrough process is an important mechanism for flow in addition to capillary displacement. Our findings may have important consequences for later testing and estimation of CO2 breakthrough pressure and flow in shale.

Laboratory core flooding experiment was run to investigate the joint use of electrical resistivity, ultrasonic velocities and 3D images of fluid distribution to improve current understanding of CO2 and brine behaviour during drainage and imbibition in reservoir rocks. The test specimen was cylindrical Rothbach sandstone measuring 100 mm in length and 38 mm in diameter, with a porosity of 23% and an average permeability of 400 mD. The brine saturated specimen was drained by injecting CO2 and later imbibed with brine while monitoring changes in resistivity and ultrasonic velocity measurements. Actual fluid saturation level and distribution have been mapped simultaneously using X-ray CT scan. CO2 saturation calculations based on CT values showed a steep saturation gradient at start of drainage and the gradient flattened with more CO2 injected into the sample. The ultrasonic compressional velocity (V-p) measurements depicted a continuous decrease with increase in CO2 saturation while the resistivity of the sample increased proportionally with increase in CO2 saturation. A CO2 saturation of 53% was achieved at the end of drainage after injection of 20 pore volume (PV) CO2. This resulted in a decrease of V-p by 7.2% while the amplitude decreased by as much as 48%. At the end of drainage, the resistivity of the sample increased to 13.9 Omega-m from full brine saturated value of 3.2 Omega-m. During imbibition, the sample was re-saturated close to 100% after 10 PV brine injection. Change in V-p due to CO2 saturation level variation was relatively consistent during drainage and imbibition (no hysteresis) where as the resistivity of the sample was more affected by the flooding history resulting in hysteretic variation in resistivity. Resistivity index (RI) values did not show a consistent pattern and a single Archie's saturation exponent (n) could not be assigned. (C) 2011 Published by Elsevier Ltd.

SUCCESS is a Center for Environmental Energy Research in Norway and performs research related to geological storage of CO2 in the subsurface. The SUCCESS centre is established by the Research Council of Norway together with several Norwegian research institutes and universities. The centre is hosted by Christian Michelsen Research. Through international cooperation and open research the SUCCESS centre will fill gaps in strategic knowledge and provide a system for learning and development of new competency to ensure safe and effective CO2 injection, storage and monitoring. In this paper we briefly present the main focus areas of the centre and some recent results obtained by the research partners. The results relate to geochemical effects, reservoir modeling, monitoring the geomechanical respond and the marine environment. A brief status on the field trial, Longyearbyen CO2 Lab, at Svalbard is also provided.

PreviousNext No AccessSEG Technical Program Expanded Abstracts 2010Moment tensor analysis and comparison of acoustic emission data with synthetic data from Spectral Element MethodAuthors: Volker OyeHorn Nath GhartiEyvind AkerDaniela KühnVolker OyeNORSAR, Gunnar Randers vei 15, 2007 Kjeller, NorwayNGI, Postboks 3930, Ullevål Stadion, 0806 Oslo, NorwaySearch for more papers by this author, Horn Nath GhartiNORSAR, Gunnar Randers vei 15, 2007 Kjeller, NorwayNGI, Postboks 3930, Ullevål Stadion, 0806 Oslo, NorwaySearch for more papers by this author, Eyvind AkerNORSAR, Gunnar Randers vei 15, 2007 Kjeller, NorwayNGI, Postboks 3930, Ullevål Stadion, 0806 Oslo, NorwaySearch for more papers by this author, and Daniela KühnNORSAR, Gunnar Randers vei 15, 2007 Kjeller, NorwayNGI, Postboks 3930, Ullevål Stadion, 0806 Oslo, NorwaySearch for more papers by this authorhttps://doi.org/10.1190/1.3513260 SectionsSupplemental MaterialAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract A laboratory experiment has been conducted on a sandstone sample where a small hole has been drilled through the middle of the sample. The intention is to simulate borehole breakout effects and to observe non‐ double couple acoustic emission events. We then determine full moment tensors for acoustic emission data from the tri‐ axial laboratory experiment. The full moment tensor inversion uses the first motion polarity and amplitude information as input parameters. The observed data from the laboratory experiment are then compared with synthetic data from a Spectral Element Method simulation using hexahedron elements, which are discretized using high‐ degree Lagrange interpolants. We find good correlation between X‐ray images of the sample and the determined locations, as well as similarities between the synthetic and the observed acoustic emission waveforms.Permalink: https://doi.org/10.1190/1.3513260FiguresReferencesRelatedDetailsCited ByApplication of an elastoplastic spectral-element method to 3D slope stability analysis25 April 2012 | International Journal for Numerical Methods in Engineering, Vol. 91, No. 1Simulation of multistage excavation based on a 3D spectral-element methodComputers & Structures, Vol. 100-101 SEG Technical Program Expanded Abstracts 2010ISSN (print):1052-3812 ISSN (online):1949-4645Copyright: 2010 Pages: 4453 publication data© 2010 Copyright © 2010 Society of Exploration GeophysicistsPublisher:Society of Exploration Geophysicists HistoryPublished: 21 Oct 2010 CITATION INFORMATION Volker Oye, Horn Nath Gharti, Eyvind Aker, and Daniela Kühn, (2010), "Moment tensor analysis and comparison of acoustic emission data with synthetic data from Spectral Element Method," SEG Technical Program Expanded Abstracts : 2105-2109. https://doi.org/10.1190/1.3513260 Plain-Language Summary PDF DownloadLoading ...

At In Salah, Algeria, excess CO2 from the produced oil and gas is re-injected into the ground as part of a CO2 storage demonstration project where one of the main goals is to verify long-term storage capacity from short-term monitoring. In this context, a significant heave at the injection sites is observed and a 3D FEM model is defined to verify it. Some additional features are introduced to investigate the impact of certain model parameters; (1) introduction of a high-permeable lower-caprock to investigate the effect on the heave from highly fractured media above the reservoir and (2) the effect of a vertical fault plane in the model to investigate the heavesignature on the surface when a fault intersects the caprock. The high observed uplift of the surface above the injection site is supported by simulations. Most of the observed uplift can be explained by the poro-elastic expansion of the injection zone. It is also shown that by looking at time evolution curves of surface heave and heave footprint at the surface above an injection site it is possible to say something about the geology, like highpermeable fracture zones and fault planes.

Safe short term storage of CO2 depends mainly on structural trapping; migration of injected CO2 is blocked by impermeable cap rock, and solubility trapping; CO2 dissolves in pore water. On longer term, mineral trapping is also contributing to the trapping of CO2. To be able to investigate the importance of these different storage mechanisms, a finite element model for simulation of CO2 injection has been developed in COMSOL Multiphysics. The model describes and solves for two-phase flow (including dissolution of CO2 in water) and fully coupled two-way interaction between the fluid flow and the solid displacement using elastic linear Biot poroelasticity theory. A rudimentary model is presented here to illustrate the practical use of the model by determining the flow regime (considering dissolution of CO2) and the stress distribution due to CO2 injection into a formation. The most important mechanisms for CO2 storage seems to be residual and solubility trapping. Good storage conditions can be reservoirs with high air entry pressure values, since this tends to diffuse the CO2 phase very efficiently.

The long-term safety of future CO2 storage projects in aquifers will not only rely on a comprehensive geological characterisation of the formation and capillary seal, but also on the ability to effectively monitor the underground migration of CO2 to allow immediate and effective remediation to prevent CO2 from escaping to the atmosphere in case of leakage. To achieve such effective remediation it is necessary that deep-probing monitoring tools can detect any leakage at an early stage long before CO2 has reached the surface. It will also be necessary to conduct shallow monitoring, at the perimeter of the storage system, where leakage to the atmosphere or ocean is imminent. Field-scale experimental observations have been designed and planned to study the sensitivity of various existing monitoring systems as a mean of monitoring CO2 leakage. Two onshore geological formations in Norway have been identified as suitable for systematic studies of detection limits for monitoring technologies in a wellcontrolled geological environment. One of the sites consists of Quaternary unconsolidated sand with a high porosity and permeability, allowing fast CO2 plume rise and the possibility of creating chimney-like plumes. The other site is a low-permeable Permian consolidated sandstone, where viscous forces will be stronger during the injection phase, thus permitting more variations in the plume shape depending on the injection rate. At both selected sites, small amounts of CO2 will be injected into the geological formations, which have no seal that will prevent the CO2 upward migration through the underground strata. The CO2 plumes will therefore mimic a potential leakage from an actual storage site and, by frequently repeating monitoring measurements, the performance of different methods will be tested. These monitoring measurements will include geophysical, down-hole, ecological/environmental, chemical/geochemical, atmospheric, and satellite methods. The results of the project will illustrate the performance of different monitoring technologies and provide reference for further developments of the methods, if needed. Various research organisations from United Kingdom, France and Norway will participate in the design and implementation of this project along with the project’s industrial partners.

Leakage of CO(2) into the atmosphere is the most crucial concern for geological storage of anthropogenic CO(2). Leakage routes could develop through existing wells and pipelines, but also by natural migration of CO(2) rich pore-fluid through the caprock and in fault zones. Therefore, a thorough geological characterization of the prospective formation identifying seal capacity, integrity and possible migration pathways must be performed prior to injection of CO(2). A caprock is a low permeable confining layer trapping CO(2) stored in a reservoir rock. Although the caprock acts as a seal, its lower boundary will be in contact with CO(2) saturated pore water or even pure CO(2). Chemical interaction between the pore fluid and the caprock may change its material properties. The aim of this study is to increase our understanding of the interaction between CO(2) and caprock, focusing on the microstructural properties of the rock. A flow through cell is used to flood a shale core (40 mm long and 38 mm diameter) with supercritical CO(2) at a temperature of 35 degrees C and at pressures above 7.5 MPa. A pressure gradient is applied across the sample to obtain a breakthrough of CO(2) in the core. During flooding both axial and radial strain of the core are measured together with the acoustic velocities in the axial direction. The measurements are performed both for the brine saturated core and at various stages during flooding with CO(2). The experimental results suggest flow of CO(2) along defined pathways within the shale. These pathways are likely to be controlled by the increasing pore pressure at the bottom of the sample which allows reopening of the cracks in the lower part of the sample, allowing CO(2) to enter the shale. Flow of CO(2) into the cracks in the lower part of the sample is followed by percolation of CO(2) in the upper part of the sample where the effective pressure is higher and crack reopening is less likely to occur. (C) 2009 Elsevier Ltd. All rights reserved.