Borehole Scale Research Articles

Analytical investigation of well/perforation scale effect on sand production of weakly consolidated sandstones

Investigating the risk of sand production is a common practice for developing unconsolidated and weakly consolidated reservoirs, particularly with designing the completion system of development wells. The risk of sanding may be different for open hole and cased and perforated completion systems. Part of this difference is a result of the different size of the boreholes—that is, open hole versus perforation tunnels— which is known as borehole scale effect. The amount of research dedicated to investigate the borehole scale effect on sand production is very limited. Research has been carried out by conducting thick-walled cylinder (TWC) tests on samples with different inner to outer diameter ratios. The impacts of sample size and boundaries on the induced stresses around the borehole and failure were, however, not differentiated from the borehole scale effect. In this paper, a comprehensive analytical approach is performed to investigate the effect of the size of the sample and boundaries on TWC tests and borehole failure. To do this, four different failure criteria—Mohr-Coulomb, Drucker-Prager, Mogi and modified Lade—are compared with previously published experimental results. The analysis shows that the size of the sample and the boundaries may significantly change the TWC strength of the rock. The TWC changes by different inner to outer diameter ratios, however, may not be fully justified by the analytical approach. Hence, a scale effect factor must be introduced to replicate the experimental results.

Numerical interpretation of gas-injection tests at different scales

Abstract To investigate gas-migration processes in saturated low-permeability argillaceous rocks, gas-injection tests under different injection pressures were carried out at different scales: on core samples at the laboratory scale; in the packed-off section of boreholes at the borehole scale (HG-B); and in the sealed microtunnel at the tunnel scale (HG-A) – a 1:2 scale experiment at the Mont Terri Rock Laboratory, Switzerland. All three tests at the Mont Terri Rock Laboratory involved Opalinus Clay. A fully coupled hydromechanical model has been developed that takes account of elastic and plastic anisotropies, anisotropic two-phase flow based on the van Genuchten function, and permeability changes when evaluating the experimental data. Two different flow regimes were studied: two-phase flow under low gas-injection pressure and dilatancy-controlled gas flow under high gas-injection pressure above the confining pressure in the laboratory experiment or the minimal principal stress in situ . When dealing with the dilatancy-controlled gas-flow regime, special consideration was made by applying two permeability approaches in which (i) the permeability change was pore-gas-pressure dependent and (ii) where the permeability change was deformation dependent. Using the parameter values determined by laboratory data, the in situ borehole tests obtained under well-defined hydromechanical conditions could be analysed accordingly. The gas-flow regime in large-scale experiments, as in the case of HG-A, is mainly governed by experimental circumstances: in this case, the excavation-induced fractures around an opening with a permeability four order of magnitude higher than that in the undisturbed rock mass.

On the role of low-permeability beds in the acquisition of F and SO4 concentrations in a multi-layer aquifer, South-West France

Fluoride (F−) commonly threatens groundwater quality. This is the case around the city of Bordeaux (France), where numerous wells tapping the thick and complex Eocene aquifer are contaminated by fluoride, which presents an issue for drinking water supply. The joint analysis of the spatial distribution of fluoride with other species like sulfate suggests that concentrations are mainly related to the occurrence of low-permeability layers containing evaporites or fluorite deposits. In order to identify the origin of the observed concentrations, a radial flow and transport model is implemented at the borehole scale. The hydraulic conductivity of the low-permeability layers and the vertical dispersivity of the aquifer were optimized to match the observed values of sulfate and fluoride concentrations. Interestingly, each of these parameters influences differently the simulated concentrations. This model has been successfully implemented to a neighboring well with the same parameter values, which tests the approach. The major conclusions drawn are: (i) the contamination in fluoride originates from the low-permeability layers, (ii) every low-permeability layer intercepted by the well releases fluoride (iii) Contamination not only originates from pore water of low-permeability layers, but may persist with long-term pumping due to mineral dissolution. As a consequence, fluoride contamination is likely to persist for a long time and the only solution to reduce fluoride concentration in abstracted water is to seal well screens facing low-permeability layers.

Selection of monitoring techniques for a carbon storage and enhanced coalbed methane recovery pilot test in the Central Appalachian Basin

The goals of monitoring, verification, and accounting (MVA) for carbon capture, utilization, and storage (CCUS) studies include improved understanding of injection and storage processes, evaluation of interactions among carbon dioxide (CO2), reservoir fluids, and formation solids, and assessment and minimization of environmental impacts (DOE and NETL, 2009). Site-specific selection of tools for a well-rounded MVA program may include technologies for atmospheric, near-surface, and subsurface monitoring.An upcoming small-scale CCUS study in an active coalbed methane field in Buchanan County, Virginia, presents a unique application for several established, effective MVA methods. The study will involve injecting up to 20,000tonnes of CO2 into three injection wells over a one-year period in order to test the injection and storage potential of the coal seams and to assess the potential for enhanced coalbed methane (ECBM) recovery at offset production wells. The reservoir consists of approximately 15 to 20 coal seams, averaging 0.3m (1.0ft) in thickness and distributed over 300m (1000ft) of vertical section. This reservoir geometry creates an unusual target for CO2 injection and also a challenging one for many monitoring and imaging techniques. MVA for the Buchanan County test will include gas content measurements at offset wells, groundwater monitoring, injectate tracer analysis, well logging, surface deformation measurement, passive microseismic monitoring, and tomographic fracture imaging. Multiple monitoring wells will be drilled in order to facilitate the MVA efforts. Surface deformation measurement, microseismic monitoring, and tomographic fracture imaging are state-of-the art tools that have potential to define the subsurface CO2 plume beyond the borehole scale. The results of the MVA program for the Buchanan County injection demonstration can be used to improve design for potential future studies of CCUS in thin coals.

Differentiated characterization of karst aquifers: some contributions

Because of the small radius of investigation of hydrogeological standard testing methods, the characterization of karst aquifers is still a challenge. The development of a karst conduit system introduces an element of large contrast in hydraulic conductivity in the hydraulic parameter field of a karst aquifer. It leads to complex flow patterns and transport phenomena that differ significantly from those observed in porous and fissured media. While on a local, i.e., borehole scale, the fissured matrix of karst aquifers can be regarded as a continuum, on a regional, i.e., catchment scale, the drainage of the aquifer system is controlled by the conduit system, which may have a highly anisotropic geometry. Therefore, characterization of karst aquifers requires a differentiated approach by the combination of various hydrogeological field methods or the application of large-scale tests, which cover the scale of dominant aquifer heterogeneities. Existing numerical modeling approaches can be applied for integral data interpretation on catchment scale.

Reservoir mapping: the latest development in well placement

The PTTEP Australasia Montara development wells were recently drilled using a new deep-directional electromagnetic-resistivity tool, which enabled the simultaneous real-time mapping of multiple and varied geological and fluid boundaries in a thick reservoir, through the entire length of the horizontal section. Conventionally, geosteering is undertaken using borehole-scale measurements; data at this scale requires the wellbore to come in close proximity or cross a feature before it is detected. This scale of measurement is good for finer detail features but does not allow for visualisation of the geology beyond what it is measured at or just beyond the borehole wall. Nor does it enable a refinement of the geophysical subsurface unless at points of contact between the well and the feature that needs to be avoided. To bridge the gap between surface seismic resolution and measurements obtained at the borehole scale, a new deep-directional electromagnetic tool sensitive to variable resistivities but able to identify boundaries tens of metres away was required. The past decade has shown a significant development in resistivity measurement technology providing directional resistivity at a significantly larger scale than conventional logging tools. The first generation allowed wells to be placed proactively, removing the need to cross the boundary or be very close to it before it was identified. This latest generation of proactive geosteering tools has been developed to remove this gap, allowing for a refinement in geophysical/geological models and a new methodology in geosteering, moving the game from boundary to reservoir geosteering.

4D Seismic for Reservoir Management in Carbonates: Does It Work?

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144228, ’Application of 4D Seismic for Reservoir Management in Carbonates: Does It Work?,’ by Mohamed Saleh Efnik, SPE, and Samsudin Haj Taib, University of Malaya, prepared for the 2011 SPE Enhanced Oil Recovery Conference, Kuala Lumpur, 19-21 July. The paper has not been peer reviewed. In the past 10 years, time-lapse (4D) seismic has evolved from an academic research topic to a typical method of monitoring reservoir performance. The method is used to provide evidence of saturation changes within the reservoir at field scale. 4D seismic provides data that describe the dynamic behavior of reservoir fluid between wells that otherwise would be limited to small-scale monitoring at borehole scale. Thus, 4D seismic provides sophisticated techniques of reservoir monitoring and management that rely on the integration of geological models, static and dynamic properties of the reservoir rock, and detailed field-production and -pressure data. Introduction The feasibility of 4D seismic has evolved with studies that showed that certain rock properties, such as acoustics and pressure, are affected by changes caused by hydrocarbon production over the life of the field. The use of 4D-seismic data in conjunction with reservoir-simulation models and production data enables creation of an internally consistent subsurface model. It has been shown that acoustic impedance (AI) and Poisson’s ratio are related closely to porosity and water-saturation changes in Arne chalks. An increase in porosity causes a decrease in AI; increasing water saturation (at constant porosity) results in a strong increase in Poisson’s ratio. An extensive seismic program was carried out over a CO2-injection area during a 5-year span to monitor the CO2 storage in a saline aquifer in the North Sea Utsira sand. 4D seismic and other geo-physical techniques were used to obtain information that could help determine reservoir-quality characteristics and predict fluid contacts. Forward modeling of 4D seismic has been shown to be a useful reservoir-management tool. Here, the simulation model was combined with the streamline method for modeling flow, and the ray-Born method for synthetic seismograms was used to compensate for the numerically expensive model because of the large volumes in the subsurface.

Magnetic inference of in situ open microcracks in sandstone samples from the Taiwan Chelungpu Fault Drilling Project (TCDP)

This paper presents a thorough magnetic study of centimeter-sized rock samples from Hole B of the Taiwan Chelungpu Fault Drilling Project (TCDP). Fabrics were obtained from magnetic susceptibility and anhysteretic remanent magnetization are interpreted using whole rock and magnetic mineralogy characterization. We infer the presence in the sandstone lithology of secondary magnetite coating a dense network of microcracks. Using other evidence from ferrofluid saturation experiments, we conclude that this network of microcracks is not sealed but open in situ, and should therefore be incorporated in the interpretation of seismic and borehole scale studies in the TCDP area.

A methodology for using borehole temperature-depth profiles under ambient, single and cross-borehole pumping conditions to estimate fracture hydraulic properties

Temperature profiles in the subsurface are known to be sensitive to groundwater flow. Here we show that they are also strongly related to vertical flow in the boreholes themselves. Based on a numerical model of flow and heat transfer at the borehole scale, we propose a method to invert temperature measurements to derive borehole flow velocities. This method is applied to an experimental site in fractured crystalline rocks. Vertical flow velocities deduced from the inversion of temperature measurements are compared with direct heat-pulse flowmeter measurements showing a good agreement over two orders of magnitudes. Applying this methodology under ambient, single and cross-borehole pumping conditions allows us to estimate fracture hydraulic head and local transmissivity, as well as inter-borehole fracture connectivity. Thus, these results provide new insights on how to include temperature profiles in inverse problems for estimating hydraulic fracture properties.

Structural styles across the Nankai accretionary prism revealed from LWD borehole images and their correlation with seismic profile and core data: Results from NanTroSEIZE Stage 1 expeditions

[1] Four drill sites of IODP NanTroSEIZE Stage 1 Expedition transected the Nankai Trough, offshore SW Japan, from the deformation front to the Kumano fore-arc basin. Borehole resistivity images from the logging-while-drilling (LWD) data were analyzed to extract orientations of faults, fractures, and bedding planes to examine the structural styles. On the basis of these features, drilling intervals were classified into fore-arc basin deposits, surface slope sediments, and deformed accretionary wedge, and these can be compared with characteristics from seismic profiles and core structural data. Bedding orientations identified in these three data sets are generally comparable, but the difference in resolution between the data sets produces different results in interpretation where geology is highly deformed or includes finer internal structures. Faults can also be correlated between these three data sets, but the differences in their appearance require special attention for accurate correlation. Many faults imaged in seismic profiles actually consist of microfracture systems, as shown in cores, that can also be identified in borehole images. Some clear faults in seismic profiles cannot be identified in borehole images, probably because of their minimal resistivity contrast with the surrounding rocks or a more complex fault zone at the borehole scale. These results suggest that these three data sets can be used to extract not only the general structure but also different styles of deformation at different scales from core samples (mm to cm), to LWD (mm to 10 m), to seismic (10 m to tens of km). This correlation requires a deep understanding of the resolution and shortcomings of each methodology.

Lithological and Petrophysical Core-Log Interpretation in CO2SINK, the European CO2 Onshore Research Storage and Verification Project

SummaryThe storage of carbon dioxide (CO2) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from power plants to the atmosphere and to mitigate global climate change. The CO2SINK (CO2 Storage by Injection into a saline aquifer at Ketzin) project is a research and development (R&D) project, mainly supported by the European Commission, the German Federal Ministry of Education and Research, and the German Federal Ministry of Economics and Technology, targeted at developing an in-situ laboratory for CO2 storage.The preparatory phase of the project involved a baseline geological-site exploration and the drilling of one injection and two observation wells, as well as the acquisition of a geophysical baseline and geochemical monitoring, in Ketzin, located near Berlin. The target saline aquifer is the lithologically heterogeneous Triassic Stuttgart formation, situated at approximately 630- to 710-m (2,070- to 2,330-ft) depth. A comprehensive borehole-logging program was performed consisting of routine well logging complemented with an enhanced logging program for one well that recorded nuclear-magnetic-resonance (NMR) and borehole-resistivity images, to characterize the storage formation better. A core analysis program carried out on reservoir rock and caprock included measurements of helium porosity, nitrogen permeability, and brine permeability at different pressure conditions.The saline aquifer at Ketzin shows a variable porosity/permeability distribution, which is related to grain size, facies variation, and rock cementation with values in the range from 5 to > 35% and 0.02 to > 5,000 md for porosity and permeability, respectively. On the basis of core analysis and logging data, an elemental loganalysis model for the target formation was established for all three wells. In addition, permeability was estimated using the Coates equation and compared with core data and NMR log-derived permeability, which seems to provide meaningful permeability estimates for the Ketzin reservoir. On the basis of the good core control that guided the petrophysical well-log interpretation in the first two CO2SINK wells, a porosity and permeability prediction by analogy for the third well is appropriate and applicable. The availability of cores was crucial for a sophisticated formation evaluation at borehole scale that characterizes the real subsurface conditions.

Comparison of alternative methodologies for identifying and characterizing preferential flow paths in heterogeneous aquifers

One of the main difficulties encountered when characterizing the hydrodynamic properties of a fractured aquifer is to identify the preferential flow paths within it. Different methods may be applied to determine the variability of the permeability at the borehole scale and to image the structure of the main flow zones between boreholes. In this paper, we compare the information obtained from different measurement techniques performed in a set of three 100 m depth wells (well-to-well spacing: 5­10 m) in a fractured crystalline rock setting. Geophysical logging and borehole-wall imaging are used to identify open and closed fractures intersecting the boreholes and their orientation. The comparison with flowmeter and single packer tests shows that few of the fractures interpreted as open from geophysical logs are significantly transmissive. Cross-borehole connectivity is first investigated from single packer tests with pressure monitoring in adjacent boreholes. To determine fracture zone connectivity, we propose a methodology simply based on the variation with packer depth of the ratio of the drawdown in the observation well and the drawdown in the pumping well. The results are compared to the analysis of cross-borehole flowmeter tests. We show that both methods provide consistent results with a similar level of information on connectivity.

Relationship between hydraulic conductivity and fracture properties estimated from packer tests and borehole data in a fractured granite

Hydraulic conductivity is closely related to fracture characteristics like fracture aperture and frequency, fracture length, fracture orientation and angle, fracture interconnectivity, filling materials, and fracture plane features. In this study, water injection tests were conducted at six boreholes of different depths drilled in fractured granite in the Mt. Geumjeong area, Korea. Hydraulic conductivity was calculated using the USBR (United States Bureau of Reclamation) water injection test method. Hydraulic conductivity was related to fracture frequency, squared fracture aperture, and the squared aperture of major fracture orientation obtained from acoustic televiewer and core log data. Fracture aperture had a stronger relationship to hydraulic conductivity than fracture frequency did. In addition, the correlation between transmissivity and cubed fracture aperture was higher than the correlation between hydraulic conductivity and the squared fracture aperture. The squared aperture with respect to major fracture orientation had a weaker correlation with hydraulic conductivity than the squared aperture using all fracture orientations. This suggests greater complexity for groundwater flow at the borehole scale compared to the regional scale. Meanwhile, the correlation coefficient between hydraulic conductivity and fracture frequency obtained from acoustic televiewer data was higher than that from core log data.

Q&A with John Gibson (April 2006)

You have been with Paradigm now since April 2005. What changes have occurred at the company since then? The first three or four months I was here, I was just a director. Then I began to get more excited about what was possible here, and I migrated to being Chairman, then Executive Chairman, and then Executive Chairman and CEO. So I have been in that role about 6 months. What really excited me about the company is that we have tremendous researchers, great scientific products, and an opportunity to make a real difference in the industry with our technology. The owner, the employees, and I all believe that there is a lot of opportunity for Paradigm, and we have organized ourselves to take advantage of that opportunity. We have made a lot of changes, all in light of trying to grow the company to become the number one provider of high-end tools in the industry. We have brought in a tremendous executive team over the last year. We brought in new sales leadership, marketing and financial leadership, and development leadership. We have made a tremendous number of changes, but at the same time, we had a record quarter for software in the fourth quarter. So it is a case where we think we have taken the wings off the airplane and gotten them back on while in flight without doing any damage to the passengers. What are Paradigm's leading-edge technologies? The industry has tremendous data-management solutions for corporate data management that are already in existence, and we see our competitors doing a very good job of supporting multiclient data access. We also see tremendous offerings from competitors in reservoir simulation, and fluid flow and simulation is an area already covered. So you ask yourself, "What is it that really needs focus in the industry?" And that is what Paradigm's strength is. I think that over the next 10 years, you are going to see tremendous advances in geophysics and petrophysics coming together. It is taking microdata at the borehole scale and combining it with macrodata such as seismic and making sure that you have the right correlation and the right attribute model to carry into reservoir characterization. So we are integrating petrophysics and geophysics, which really gives us a leadership position in rock and fluid interpretation. What is Paradigm's growth strategy? The industry's move toward optimizing production means that petrophysics becomes a real driver in every decision on every desktop, and we have a leadership position in petrophysics. And when you leverage it with the geophysics, you give the petrophysicists the ability to see across the whole reservoir and the geophysicists the opportunity to incorporate rock and fluid analysis from the borehole. As the industry tries to enhance recovery, to get another 8% or 20% or 2%, it is those two disciplines combined on the front end for interpretation of the rock and fluids in their spatial positions and how they are changing dynamically over time that is really going to bring all of the value in the industry. Our growth will be a result of that becoming the focus.

Assessment of preferential flow path connectivity and hydraulic properties at single-borehole and cross-borehole scales in a fractured aquifer

Summary Preferential flow path connectivity is generally cited to explain scaling effects in hydraulic properties [Hsieh, P.A., 1998. Scale effects in fluid flow through fractured geological media, Scale dependence and scale invariance in hydrology. Cambridge University Press, pp. 335–353; Illman, W.A., in press. Strong evidence of directional permeability scale effect in fractured rock. Journal of Hydrology]. However, this information is rarely available in the field. In this study, we present a characterization of flow paths connectivity at the Plœmeur fractured crystalline aquifer from cross-borehole flowmeter tests. We show that high transmissivity zones are connected over distances of at least 150 m all over the site. In parallel, we synthesize hydraulic properties estimates obtained at this site from field techniques having distinct scales of investigation: single borehole flowmeter experiments, cross borehole flowmeter experiments and long term pumping tests. We find that borehole scale variability of transmissivity estimates vanishes at larger scale and that the transmissivity converges towards the high values of the transmissivity distribution. This effect may be explained by the organization of the flow field in the subsurface, and particularly the good connectivity of the permeable zones all over the site.

Attenuation analysis of acoustic waveforms in a borehole intercepted by a sand-shale sequence reservoir

We applied a new processing algorithm to extract intrinsic attenuation (1/Q) from the head P-wave of a full waveform sonic log. The sonic log was acquired in an oil reservoir in northeast Texas (USA). The reservoir is a sand-shale sequence characterized at the pore, core, and borehole scales. We found that the attenuation correlates with the lithology, including a sandstone zone partially saturated with oil and water. A comparison of 1/Q with the microseismogram and the petrophysics of other well logs provides a way of evaluating the consistency of Q at each borehole depth location. An analysis of the results explains the different attenuation anomalies found in the Q log.

Cross‐Borehole Flowmeter Tests for Transient Heads in Heterogeneous Aquifers

Cross-borehole flowmeter tests have been proposed as an efficient method to investigate preferential flowpaths in heterogeneous aquifers, which is a major task in the characterization of fractured aquifers. Cross-borehole flowmeter tests are based on the idea that changing the pumping conditions in a given aquifer will modify the hydraulic head distribution in large-scale flowpaths, producing measurable changes in the vertical flow profiles in observation boreholes. However, inversion of flow measurements to derive flowpath geometry and connectivity and to characterize their hydraulic properties is still a subject of research. In this study, we propose a framework for cross-borehole flowmeter test interpretation that is based on a two-scale conceptual model: discrete fractures at the borehole scale and zones of interconnected fractures at the aquifer scale. We propose that the two problems may be solved independently. The first inverse problem consists of estimating the hydraulic head variations that drive the transient borehole flow observed in the cross-borehole flowmeter experiments. The second inverse problem is related to estimating the geometry and hydraulic properties of large-scale flowpaths in the region between pumping and observation wells that are compatible with the head variations deduced from the first problem. To solve the borehole-scale problem, we treat the transient flow data as a series of quasi-steady flow conditions and solve for the hydraulic head changes in individual fractures required to produce these data. The consistency of the method is verified using field experiments performed in a fractured-rock aquifer.

Use of hydraulic tests at different scales to characterize fracture network properties in the weathered‐fractured layer of a hard rock aquifer

The hydrodynamic properties of the weathered‐fractured layer of a hard‐rock pilot watershed in a granitic terrain are characterized using hydraulic tests at different scales. The interpretation of numerous slug tests leads us to characterize the statistical distribution of local permeabilities in the wells. The application of flowmeter profiles during injection tests determines the vertical distribution of conductive fracture zones and their permeabilities. It appears that the extension of the most conductive part of the weathered‐fractured layer is limited down to 35 m depth. The partition of drainage porosity between blocks (90%) and fractures (10%) is determined thanks to the interpretation of pumping tests using a double‐porosity model. The application of anisotropic and single‐fracture analytical solutions on pumping test data allows us to determine, respectively, the degree of anisotropy of permeability (Kr/Kz = 10) and the radius (4–16 m) of the horizontal conductive fractures crossed by the wells. Two different scales of fracture networks are identified: the primary fracture network (PFN), which affects the matrix on a decimeter scale by contributing to an increase in the permeability and storage capacity of the blocks, and the secondary fracture network (SFN), which affects the blocks at the borehole scale. SFN is composed of two sets of fractures. The main set of horizontal fractures is responsible for the subhorizontal permeability of the weathered‐fractured layer. A second set of less permeable subvertical fractures insures the connectivity of the aquifer at the borehole scale. The good connectivity of fracture networks is shown by fractional‐dimension flow solutions. The absence of scale effect in the study area suggests that the hydraulic conductivity at the borehole scale is laterally homogeneous. Finally, the analysis and synthesis of the hydrodynamic properties allow us to propose a comprehensive hydrodynamic model of the fractured‐weathered layer. Many geological and hydrogeological indicators suggest that a continuous and laterally homogeneous weathering process is responsible for the origin of the fractures and permeability encountered in the aquifer. These results confirm the major role played by weathering in the origin of fractures and on resulting hydrodynamic parameters in the shallow part of hard‐rock aquifers.

Spatial distribution of porosity and minerals in clay rocks from the Callovo-Oxfordian formation (Meuse/Haute-Marne, Eastern France)—implications on ionic species diffusion and rock sorption capability

Imaging techniques, adapted to clay rocks, combined with mathematical correlations of petrophysical parameters bring a new petrographic description of this clay rock integrating multi-scale data. Rock heterogeneities (mineral and porosity distributions) are studied at the mineral pore, the core and the borehole scale for interpreting diffusion tests. Although the infra-micrometric pores are associated with the clay particles and larger pores are associated with bioclasts and detrital minerals, especially tectosilicates, relationships between minerals and pores are quite complex at the borehole scale. They are mainly controlled by mineral spatial arrangements and contents, since micro- to macrostructures of centimetric size are encountered in each lithofacies. Effects of surface interactions and pore-constriction electrochemical controls were underscored for a large proportion of the effective porosity. Although the effective porosity is physically interconnected in the rock volume, diffusion and sorption are discussed in terms of structure and accessibility to sorption sites. These data could be the basis for the construction of a quantitative transport model by diffusion taking into account the sample heterogeneities from the mineral pore size to the centimetric core size ranges. The conceptualisation of the organization of the porosity in such low permeability clayey medium, considered together with the analysis of interface-derived effects constitutes an important step forward in understanding the mechanisms affecting the migration of single ionic species. This understanding should help in extrapolating transport parameters obtained at the centimetric scale from laboratory experiments to the geological formation scale.

About this title

This publication introduces the newly developed, integrated discipline of fracture and in-situstress characterization of hydrocarbon reservoirs, through 16 well-illustrated case studies. These cover a wide range of tools, from borehole Scale (logs and cores) to reservoir scale (3-D and 4-D seismic). It also covers surface studies (outcrop and remote sensing). In addition, it addresses the impact of fractures and in-situ stresses on fluid flows and their simulation. This volume deals with a subject that is gaining increasing interest with the advancement of technologies and shifting boundaries of marginal fields into more challenging ground. Fractures and their response to current-day in-situ stresses have become a crucial part of reservoir characterization in deep tight reservoirs. In addition, maturing reservoirs, which were considered as 'conventional' at discovery, are displaying symptoms characteristic of fractures and/or geomechanical contribution. This has lead to the need to delineate the fractures and the stresses in these reservoirs and revise reservoir management accordingly. The book will be of interest to a broad range of readers from both academic and industrial institutes, who are researching and dealing with hydrocarbon reservoir characterization, simulation and management.