Borehole Scale Research Articles

Gas-entry pressure impact on the evaluation of hydrogen migration at different scales of a deep geological disposal of radioactive waste

Although the importance of gas-entry pressure in simulating two-phase liquid–gas flow in porous media has been studied at the column and borehole scales, its impact on the simulation of transient hydraulic-gas at different scales of a deep geological repository of radioactive waste (DGR) in low permeability clay rock during the post-closure phase has not yet been studied. The purpose of this work is to show that neglecting this phenomenon can lead to underestimation of the maximum gas pressure and water–gas fluxes simulated within the host rock and backfilled drift network. This could impact the performance of the engineered barrier system of a DGR. Simulations performed for a high-level waste disposal cell and for a simplified repository composed of hundreds of disposal cells situated in a clay host rock, show that gas preferentially migrates through the DGR components with low capillary entry pressures, such as the excavation damaged zone (Refers to the zone where fractures develop due to failure of the rock mass around galleries after tunneling) (EDZ), the engineered barriers materials (backfill, bentonite-plug…) and interfaces between the EDZ and these materials. Such a result could have significant consequences on the performance of a repository, due to the accumulation of gas in the drift network and high increase of gas pressure, which could lead to the host rock hydraulic fracturing.

Electromagnetic prediction of rock thermal properties beyond boreholes: Soultz-sous-Forets (France) case study

Estimation of deep temperature, thermo-hydro-dynamic and basin simulation, heat exchange and geothermal resource assessment require knowledge of the rock thermal properties beyond boreholes. At the absence of suitable methods and instruments for such estimates we propose a new approach to prediction of thermal conductivity, specific heat capacity and heat flow density based on results of electromagnetic sounding of the study area. Artificial neural network used to this end is taught by correspondence between laboratory measurements on cores from the drilled boreholes and adjacent electrical conductivity profiles determined by inversion of the electromagnetic sounding data collected in their vicinity. This approach is used to estimate rock thermal properties along NW-SE magnetotelluric profile crossing Soultz-sous-Forêts geothermal area, Alsace, France. We demonstrate that accuracy of such prediction both in depths below the boreholes and in the interwell space is comparable with that usually achievable in the borehole scale. In particular, it is shown that relative errors of thermal conductivity prediction at depths twice as large as the borehole depth are as small as 2%, and the accuracy of cross-well thermal conductivity prediction is 6% and 10% for dry and wet rocks, respectively. On the other hand, the prediction accuracy for matrix thermal conductivity of a rock from the known profile of dry thermal conductivity is about 8%. Based on the results of our studies, we constructed dry and wet thermal conductivity sections from the electrical conductivity model determined earlier by 2-D inversion of magnetotelluric data. The temperature model of the study area built along the same profile by means of electromagnetic geothermometer and the obtained thermal conductivity sections enabled estimating the profiles of the vertical component of heat flow density at the surface from dry and wet thermal conductivity sections. They could be considered as minimum and maximum constraints, respectively, bounding the area of its possible values, which, in turn, depend on in situ thermal conductivity of fluids filling the rock pores. The range of possible vertical heat flow density variations (100–150 ± 10% mW·m− 2) agrees well with heat flow estimates in the Upper Rhine graben and, in particular, in Soultz-sous-Forêts geothermal area roughly estimated earlier from borehole measurements. Using the artificial neural network trained on the correspondence between the specific heat capacity determined in the borehole and adjacent electrical conductivity profile, we built the model of specific heat capacity. Against the background, a zone of enhanced specific heat capacity ranging between 2.05 and 2.15 MJ·m− 3·K− 1 was observed in the domain located at the base of the sedimentary cover and upper part of the granitic basement.

Implication of the micro- and lithofacies types on the quality of a gas-bearing deltaic reservoir in the Nile Delta, Egypt

The Messinian Qawasim sequence, as one of the most important reservoirs in the Egyptian Nile Delta, represents a typical gas-bearing deltaic reservoir sequence. It aims at delineating the implication of the litho- and microfacies associations on the reservoir characteristics of the different stages of the fluvial deltas including the prodelta, proximal/distal delta front, and the delta plain depositional sequences. The studied reservoir sequence was divided into two units; upper and lower clastic units. The petrophysical properties of these two units were studied on the borehole scale using the gamma-ray, caliper, sonic, density, neutron, and resistivity logs to estimate the reservoir parameters including the total and effective porosities, water saturation, shale volume, and the net-pay thickness. For more details, they are also examined on the plug-scale using the core dataset including helium porosity, density, permeability, and fluids saturations, where the flow zone indicator, the reservoir potentiality index, the reservoir quality index, and the average reservoir pore radius were then estimated. The entire sequence is divided into five reservoir rock types (RRT1-RRT5) where, the best quality is assigned to the first RRT (the upper reservoir unit), and the lowest quality is assigned to the RRT5 of the lower reservoir unit. Based on core description and the petrographical studies five lithofacies and four microfacies have been identified. The lithofacies are (1) laminated mudstones/siltstones, (2) ripple laminated sandstones, (3) cross-laminated sandstones, (4) cross-bedded sandstones, and (5) pebbly massive sandstones. These lithofacies are primarily composed of four microfacies; sublithic arenites, subarkose arenite, glauconitic quartz wacke, and sandy mudstone/siltstone. Based on this study, the pebbly massive and the cross-bedded sandstones of the upper unit which is composed of the sublithic and subarkose arenites (RRT1-RRT2) have the best reservoir quality. On the other hand, the lowest quality is assigned to the RRT5 (sandy mudstone/siltstone microfacies) which is represented on the macro scale by the laminated mudstones/siltstones lithofacies. The integration between multi-scale datasets (core-well, petrography, well logs, and seismic) gives a precise picture of the deltaic Qawasim reservoir rock units in the Nile Delta. This workflow has never been applied to the deltaic system in the onshore Nile delta and North Africa. Thereby, this study is considered a standard case study for the deltaic sequences and its proposed workflow is applicable to the Nile Delta elsewhere and worldwide for similar reservoir sequences.

Integrated geophysical, petrophysical and petrographical characterization of the carbonate and clastic reservoirs of the Waihapa Field, Taranaki Basin, New Zealand

Despite the economic importance of the Waihapa Field in Taranaki Basin in New Zealand, the structural setting, petrographic and petrophysical properties of its Cenozoic reservoirs are still poorly understood. This research integrates a 3D seismic survey with core and well logs data, as well as petrographic description in order to discuss the structural setting and the reservoir characterization of the Cenozoic reservoirs along the Waihapa Field, Taranaki Basin, New Zealand. A major thrust fault was interpreted dissecting both the Kapuni (Paleocene- Eocene) and Ngatoro (Oligocene- Early Miocene) groups and another opposite thrust fault affecting the Ngatoro Group and the Waihapa anticline. These compressional structures were resulted from the regional compression which affected the Taranaki Basin during the Miocene. Wai-iti Group (Miocene) is dissected by a set of NE-SW normal faults. These normal faults remark the end of the compressional phase and the beginning of a new extensional phase along the Taranaki Basin.The petrographic data of the studied reservoirs indicate that the Late Miocene Mount Messenger Formation is composed of feldspathic wacke, micaceous feldspathic quartz arenite and mudstone microfacies, whereas the Oligocene Tikorangi Formation is composed of five microfacies (bioclastic grainstone, bioclastic packstone, sandy wackestone, highly fractured silty mudstone and sandy glauconitic packstone microfacies). Downward, the Upper Eocene Mangahewa Formation is composed of ferruginated quartz arenite, micaceous quartz arenite, and ferruginated calcareous quartz arenite microfacies. Cementation and compaction are mostly affected the Mangahewa Formation while fracturing and dissolution are primarily affected the Tikorangi and the Mount Messenger formations respectively. The studied core data was discriminated into four petrophysical static rock types (PSRTs). The PSRT1, representing the Mount Messenger reservoir, has the best reservoir quality (av. porosity = 23.3%, av. permeability = 45.0 md, and meso pores, 2.60 μm) while the PSRT4 of Tikorangi Formation has the lowest reservoir quality (av. porosity = 5.5%, av. permeability = 0.01 md, and nano pores, 0.07 μm). The PSRT2 (av. porosity = 4.17%, av. permeability = 0.26 md, and micro pores, 0.59 μm) and PSRT3 (av. porosity = 5.93%, av. permeability = 0.08 md, and micro pores, 0.22 μm) are petrophysically considered transitional rock types between the PSRT1 and the PSRT4.However, Tikorangi reservoir is already producing oil from the borehole scale fractures. This work represents the workflow applied during integrating seismic, petrographical and petrophysical data in order to characterize carbonate and clastic reservoirs for any further hydrocarbon development plans along the field.

Three-dimensional characterization of karstic dissolution zones, fracture networks, and lithostratigraphic interfaces using GPR cubes, core logs, and petrophysics: Implications for thief zones development in carbonate reservoirs

Fractures and karstic dissolution features have been recognized to significantly affect subsurface fluid flow on a range of scales in carbonate rocks. However, due to the information gap between seismic and borehole scales, characterizing these features is a real challenge. We present a three-dimensional multidisciplinary approach to identify the main factors controlling the formation of connected rock volumes composed by permeable karstic dissolution zones. We investigate two outcrops in the Jandaíra Formation, which is an intensely fractured and karstified carbonate platform in the Potiguar Basin, Brazil. Two GPR cubes are jointly interpreted with cored boreholes, borehole images, petrophysical profiles, and thin sections. We verified that attenuated zones of GPR signal are related to secondary carbonate changes caused by fracturing and/or diagenetic alterations, leading to the development of relatively high secondary permeability. At least three types of attenuation/karstic zones might occur: fractured or broken zones affected by fracture enlargement due to dissolution, zones submitted to intense diagenetic alterations, and void spaces as a final end-member of these two processes. Fractures are preferential routes to fluid flow, thus contributing to increase dissolution processes, particularly in layers having relatively high values of primary matrix porosity and permeability. On the other hand, relevant diagenetic alterations might occur in layers that contain high concentration of stylolites. As a result of interconnecting dissolved stylolites, zones of relatively high secondary permeability can be created regardless of the primary values of matrix porosity and permeability. Geobodies of connected volumes of karstic zones often present tabular shapes and are delimited by subvertical fractures and subhorizontal lithostratigraphic interfaces. In the reservoir scale, these tabular geobodies might compose highly connected permeable volumes of altered carbonate rocks that constitute thief zones or super-K layers.

Geophysical signature of the transition zone between the sedimentary cover and the basement from an analogue of the Rhine Graben

Exploiting high temperatures geothermal resources in sedimentary and basement rocks, rifts or flexural basins to produce electricity is now possible because of the development of binary geothermal power plant technology. However it remains challenging because the presence of fluid and permeability at 4–5 km depth is necessary. A multi-scale and multi-disciplinary approach to increase our knowledge of the transition zone between the sedimentary cover and the basement have been undertaken to provide fundamental knowledge for the assessment of its geothermal potential. In this paper, we report out the results of a study performed on an exhumed transition zone in the Ringelbach area in the Vosges Mountain, on the flank of the Rhine graben. In this analogue of a deeply buried transition zone of the Rhine Graben, Triassic sandstones are still present on the top of the fractured and altered granitic basement providing the unique opportunity to study in-situ the physical properties of this transition zone. We focused here on electrical and seismic properties of the transition zone as they are the main physical parameters usually assessed with the help of geophysical methods during the exploration phase of a geothermal project.We show that altered porous and potentially permeable granite targeted in deep geothermal exploration has a clear signature on both electrical conductivity and seismic measurements that can be measured at core scale, borehole scale, and are still visible with surface geophysical methods such as refraction and reflection seismic and Controlled Source Electromagnetism at a few hundred meter depth. The results suggest that best discrimination between permeable and non permeable rocks may be provided by the joint interpretation of both resistivity and seismic velocities.

Integrated petrophysical and microfacies analyses for a reservoir quality assessment of the Asmari Dolostone sequence in the Khesht Field, SW Iran

The Asmari Formation is one of the most important prolific reservoirs along both sides of the Persian Gulf. The present study aims to characterize the fractured dolomite of the Asmari reservoir sequence in SW Iran. Such characterization can be achieved through a petrophysical reservoir characterization using core data integrated with a detailed microfacies analysis and a detailed study on the dominant diagenetic features. The detailed microfacies analysis indicates that the Asmari reservoir can be discriminated into seven non-clastic microfacies (laminated to massive anhydrite, sandy dolomudstone, peloidal bioclastic dolowackestone, peloidal foraminiferal dolowackestone/dolopackstone, peloidal bioclastic dolopackstone/dolograinstone, framestone, and dolograinstone microfacies). These microfacies have been primarily deposited in tidal flat, lagoonal, and carbonate shoal depositional environments. Petrophysically, some X-Y plots were established to present the available petrophysical core data (porosity ∅He, horizontal and vertical permeabilities, kH and kV, respectively) to enable a mathematical reservoir modeling. Besides, the reservoir quality has been defined using the flow zone indicator (FZI), reservoir quality index (RQI), and the effective pore radius (R35). Based on these petrophysical core data and quality parameters, the studied samples can be subdivided into five reservoir rock types (RRTs). Also, reservoir zonation on the borehole scale using the improved stratigraphic modified Lorenz technique (ISML) indicated that the characterized reservoir can be subdivided into four hydraulic flow units (HFU-1, HFU-2, HFU-3, and HFU-4). The HFU-2 (dolograinstone, dolopackstone, and framestone samples) is characterized by the best reservoir quality (average ∅He = 7.8%, kH = 95.2 md, RQI = 0.84 µm, FZI = 15.9 µm, and R35 = 10.5 µm); it is composed of RRT1 and RRT2 samples. On the other side, the lowest reservoir quality is assigned to the HFU-3 which is composed of the RRT5 (dolomudstone and evaporates, average ∅He = 11.5%, kH = 0.24 md, RQI = 0.04 µm, FZI = 0.22 µm, and average R35 = 0.21 µm). The prevailed reservoir characteristics of the Asmari dolostone sequence in SW Iran are mostly controlled by replacive and pervasive dolomitization, fracturing, and cementation by anhydrite.

Integration of well logs and seismic data for facies analysis and modelling of the El-Wastani Formation in the Sequoia Gas Field, offshore Nile Delta, Egypt

Reservoir rock facies modelling helps in determining the degree of reservoir variability for enhanced management of the heterologous facies’ reservoirs, both at borehole scale and more regionally at seismic scale. The Pliocene Offshore Sequoia Gas Field is located near the boundary between the Rosetta Concession and the West Delta Deep Marine Concession (WDDM) on the western side of the Nile Delta. It is characterised by canyon systems of complex turbidite channel-levee deposits that are multi-stacked. In order to create various depositional facies that are compatible with a deep marine environment, an advanced facies model was built from the combination of the seismic, core, and formation micro imager (FMI). Sandstones (laminated and massive), shale (laminated and massive mud-rock), silt, and thin sandstone beds were identified as four major facies. In the Sequoia field area, the El-Wastani Formation is known as a heterogeneous sequence of sandstones and mudstones arranged into a broad upward-fining succession. High-quality, blocky sands exist at the base, while the upper portion is characterised primarily by isolated sand bodies intercalated with mudstones in the presence of some thin-bedded sands (their thickness less than 1 m).

Modelling borehole flows from Distributed Temperature Sensing data to monitor groundwater dynamics in fractured media

Fractured aquifers are known to be very heterogeneous with complex flow path geometries. Their characterization and monitoring remain challenging despite the importance to better understand their behavior at all spatial and temporal scales. Heat and correspondingly temperature data have gained much interest in recent years and are often used as a tracer for characterizing groundwater flows. In the current work, a fast computer code is developed using Ramey and Hassan and Kabir analytical solutions which converts the temperature profile to the flow rate profile along the borehole. The method developed is validated through numerical simulations. A global sensitivity study recognizes the media thermal properties as the most influential parameters. For testing the method in the field, fiber-optic distributed temperature sensing (FO-DTS) data were used to monitor the dynamic behavior of fractured aquifers at the borehole scale at the Ploemeur-Guidel field site in Brittany, France. DTS data are used to infer the flow rates in the different sections of a fractured wellbore (flow profile) and calculate the contribution of each fracture to the total flow. DTS data were acquired for about three days in three different hydraulic conditions corresponding to two different ambient flow conditions and one pumping condition. Flow profiling using distributed temperature data matches satisfactorily with results from heat-pulse flow metering performed in parallel for cross-checking. Moreover, flow profiling reveals the daily variations of ambient flow in this fractured borehole. Furthermore, it shows that during ambient flowing conditions, shallow and deep fractures contribute roughly equally to the total flow while during the pumping condition, the deepest fractures contribute more to the total flow, suggesting a possible reorganization of flow and hydraulic heads depending on the hydraulic conditions. Thus, although the proposed method (DTS data and proposed framework) may be costlier and is based on indirect characterization through temperature measurements, it provides real-time monitoring of complex fracture interactions and recharge processes in fractured media. Thus, this method allows for a full analysis of the temporal behavior of the system with a simple and fast analytical model. Furthermore, thanks to its narrow width, DTS can be used and installed in boreholes for long-term monitoring while heat-pulse flow metering may lead to head losses in the borehole and may not be always possible depending on some borehole conditions. One of the limitations of the approach proposed is the proper knowledge of the thermal properties of media required to infer the flow rate from the temperature. Nevertheless, surface rate measurement can be useful to constrain these properties and reduce the flow profiling uncertainty. Thus, the method proposed appears to be an interesting and complementary method for characterizing borehole flows and groundwater dynamics in fractured media such as for instance, monitoring the recharge dynamic.

Tracking Fluid Flow in Shallow Crustal Fault Zones: 1. Insights From Single‐Hole Permeability Estimates

AbstractNew in situ measurements to constrain the range, distribution, and spatial (meter‐scale) variations of permeability in shallow crustal fault zones are reported based on systematic downhole tests at 0.5‐km depth in crystalline rock. Single and cross‐hole hydraulic packer tests were performed at a new dedicated test facility hosted in the Grimsel Test Site, in the Swiss Alps, following the technical instrumentation and isolation of discrete fault zones accessed by an array of boreholes. Single‐hole test results are presented in this paper, while cross‐hole experiments are reported in the companion paper. Our results reveal a sharp spatial falloff in permeability, from 10‐13 to 10‐21 m2, with off‐fault distances of 1–5 m and characterized by a power‐law relation with fracture density. Fractures linking subparallel faults were detected as high‐permeability discrete spots several meters away from off‐fault damage. Due to the narrow (centimeter‐wide) thickness of fault cores, the hydraulic tests presented in this study do not characterize the permeability of fault core materials. The transmissivity of single fractures spans six orders of magnitude (10‐12 to 10‐6 m2/s) and is systematically higher in damage zones. In situ stresses appear to have a minor effect on natural, present‐day fracture transmissivity at the borehole scale. We suggest that the geometrical and topological properties of fracture systems instead tend to control the permeability of the shallow crustal faults studied.

Hydraulic fracture propagation in a heterogeneous stress field in a crystalline rock mass

Abstract. As part of the In-situ Stimulation and Circulation (ISC) experiment, hydraulic fracturing (HF) tests were conducted in a moderately fractured crystalline rock mass at the Grimsel Test Site (GTS), Switzerland. The aim of these injection tests was to improve our understanding of processes associated with high-pressure fluid injection. A total of six HF experiments were performed in two inclined boreholes; the surrounding rock mass was accessed with 12 observation boreholes, which allows for the high-resolution monitoring of fracture fluid pressure, strain, and microseismicity in an exceptionally well-characterized rock mass. A similar injection protocol was used for all six experiments to investigate the complexity of the fracture propagation processes. At the borehole scale, these processes involved newly created tensile fractures intersecting the injection interval, while at the cross-hole scale, the natural network of fractures dominated the propagation process. The six HF experiments can be divided into two groups based on their injection location (i.e., south or north to a brittle–ductile shear zone), their similarity of injection pressures, and their response to deformation and pressure propagation. The injection tests performed in the south connect upon propagation to the brittle–ductile shear zone. Thus, the shear zone acts as a dominant drain and a constant pressure boundary. The experiments executed north of the shear zone show smaller injection pressures and larger backflow during bleed-off phases. From a seismic perspective, the injection tests show high variability in seismic response independently of the location of injection. For two injection experiments, we observe reorientation of the seismic cloud as the fracture propagated away from the wellbore. In both cases, the main propagation direction is normal to the minimum principal stress direction. The reorientation during propagation is interpreted to be related to a strong stress heterogeneity and the intersection of natural fractures striking differently than the propagating hydraulic fracture. The seismic activity was limited to about 10 m of radial distance from the injection point. In contrast, strain and pressure signals reach further into the rock mass, indicating that the process zone around the injection point is larger than the zone illuminated by seismic signals. Furthermore, strain signals indicate not just single fracture openings but also the propagation of multiple fractures. Transmissivities of injection intervals increase about 2–4 orders of magnitudes.

How Can Temperature Logs Help Identify Permeable Fractures and Define a Conceptual Model of Fluid Circulation? An Example from Deep Geothermal Wells in the Upper Rhine Graben

Identifying fluid circulation in fracture zones (FZs) is a key challenge in the extraction of deep geothermal heat from natural reservoirs in the Upper Rhine Graben. This study focuses on permeable FZs present within the granitic basement penetrated by deep geothermal well GPK-1 at Soultz and GRT-1 and GRT-2 at Rittershoffen (France). The various temperature (T) log datasets acquired from these wells during production and at equilibrium, with the associated flow logs, allow for the unique opportunity to interpret fluid circulation at the borehole scale. All permeable FZs identified by permeability indicators measured during drilling operations and from image logs spatially coincide with positive or negative T anomalies observed in the T logs during production and/or at equilibrium. However, within the FZs, partially open fractures act as narrower paths for circulation at different temperatures. These temperatures can even be estimated with confidence if the associated flow log is available. The polarity of the T anomalies correlates with the state of equilibrium of the well and thus can change over the well history. During production, the temperature of the water inflow through the fractures can be estimated relative to the mixture of water circulating below the fractures. At thermal equilibrium, the water temperature is estimated with respect to the temperature of the surrounding rock formation. Because temperature fluxes and geothermal fluids are intimately linked, T logs are a useful, reliable, and very sensitive tool to localize the inflow of geothermal water through FZs.

Estimation and mapping of vitrinite reflectance from seismic data in South Pars gas field, Persian Gulf

Due to the importance of vitrinite reflectance (Ro) data in the evaluation of petroleum basins in terms of thermal maturity of petroleum source rocks, here we estimate Ro from 3D-post-stack seismic data based on a previously developed equation. Three wells drilled into the South Pars gas field, the world's largest non-associated gas field, provide calculated Ro from well-log data and some measured Ro data from core samples. A two steps methodology is followed: 1) at bore-hole scale; and, 2) at 3D seismic scale. Firstly, the Ro is measured in a few samples and also calculated more extensively from well log data applying the recently developed method based on the separation between the cumulative frequency values of resistivity ratio (RR) and sonic log data (the ΔRRS method of Kadkhodaie and Rezaee, 2017). The high correlation coefficient and low-root mean squared error values in measured versus calculated Ro values derived from a blind well in the study area verify the validity of the results. Through the application of the integrated methodology, a 3D-volume of calculated Ro values is generated for use in thermal maturity assessment of potential source rocks both in wellbore (1D) and the field-wide scale (3D).

Predicting Structural Permeability in the Deep Coal Play, Tirrawarra-Gooranie fields, Cooper Basin

A 2D numerical stress modelling study was conducted for the Tirrawarra-Gooranie oil and gas field in the Cooper Basin, which produces from a mixture of conventional and non-conventional (deep coal) reservoirs. The aim of this study is to understand the current state of stress, both magnitudes and orientation, within the zones of interest. A high confidence 3D structural framework was used as a key input to the model, which sought to demonstrate how the in-situ stress is distributed or perturbed throughout the field. The understanding of the current stress state at borehole scale can assist with the prediction of natural fractures or structural permeability, fracture stimulation design and placement, and production performance. Extensive sensitivity studies were conducted, with the most important inputs found to be boundary stress magnitudes and stress orientation with respect to the faults. The models were interrogated at both the primary coal target and the underlying sandstone horizons. They were found to have significantly different stress states. The output models were compared against production data, 1D mechanical earth models, fracture stimulation data, image logs and core data. The model predictions are in reasonable agreement with the mechanical earth models and the stress orientations determined from the image logs. Predicted stress rotations greater than 4° from the regional stress direction appear to be associated with poorer frac placement, higher bottom hole treating pressures and poor gas rate outcomes. There is a clear association of mineralised natural fractures with areas of low differential stress. The models provide an additional element of subsurface information which will inform future appraisal activities and may improve the understanding of variability in the deep coal fracture stimulation outcomes.

Modeling Poroelastic Wave Propagation in a Real 2-D Complex Geological Structure Obtained via Self-Organizing Maps

Two main stages of seismic modeling are geological model building and numerical computation of seismic response for the model. The quality of the computed seismic response is partly related to the type of model that is built. Therefore, the model building approaches become as important as seismic forward numerical methods. For this purpose, three petrophysical facies (sands, shales and limestones) are extracted from reflection seismic data and some seismic attributes via the clustering method called Self-Organizing Maps (SOM), which, in this context, serves as a geological model building tool. This model with all its properties is the input to the Optimal Implicit Staggered Finite Difference (OISFD) algorithm to create synthetic seismograms for poroelastic, poroacoustic and elastic media. The results show a good agreement between observed and 2-D synthetic seismograms. This demonstrates that the SOM classification method enables us to extract facies from seismic data and allows us to integrate the lithology at the borehole scale with the 2-D seismic data.

High-Resolution Wellbore Temperature Logging Combined with a Borehole-Scale Heat Budget: Conceptual and Analytical Approaches to Characterize Hydraulically Active Fractures and Groundwater Origin

This work aims to provide an overview of the thermal processes that shape wellbore temperature profiles under static and dynamic conditions. Understanding of the respective influences of advection and conduction heat fluxes is improved through the use of a new heat budget at the borehole scale. Keeping in mind the thermal processes involved, a qualitative interpretation of the temperature profiles allows the occurrence, the position, and the origin of groundwater flowing into wellbores from hydraulically active fractures to be constrained. With the use of a heat budget developed at the borehole scale, temperature logging efficiency has been quantitatively enhanced and allows inflow temperatures to be calculated through the simultaneous use of a flowmeter. Under certain hydraulic or pumping conditions, both inflow intensities and associated temperatures can also be directly modelled from temperature data and the use of the heat budget. Theoretical and applied examples of the heat budget application are provided. Applied examples are shown using high-resolution temperature logging, spinner flow metering, and televiewing for three wells installed in fractured bedrock aquifers in the St-Lawrence Lowlands, Quebec, Canada. Through relatively rapid manipulations, thermal measurements in such cases can be used to detect the intervals or discrete positions of hydraulically active fractures in wellbores, as well as the existence of ambient flows with a high degree of sensitivity, even at very low flows. Heat budget calculations at the borehole scale during pumping indicate that heat advection fluxes rapidly dominate over heat conduction fluxes with the borehole wall. The full characterization of inflow intensities provides information about the distribution of hydraulic properties with depth. The full knowledge of inflow temperatures indicates horizons that are drained from within the aquifer, providing advantageous information on the depth from which groundwater originates during pumping.

Geomechanical restoration as a tool for fractured reservoir characterization: Application to the Permian Basin, west Texas

We present a three-dimensional (3-D) geomechanical-restoration method as a reservoir characterization tool in the Permian Basin, west Texas. The Oates SW field produces gas from the Lower Devonian Thirtyone Formation within structural traps. The Thirtyone is a brittle chert with characteristics of a fractured reservoir: field development has experienced variable production trends for decades. To assess the impact of deformation on reservoir properties, we employ 3-D geomechanical restorations to model strain patterns associated with fault displacement and fold growth. We correlate these model strains with independent measures of natural rock strain to assess the viability of the restoration results. A semblance volume generated from 3-D seismic reflection data illuminates secondary faults and fracture zones that are not incorporated in the geomechanical restorations. Our analysis yields strong correlations between low semblance and elevated strain throughout the Thirtyone reservoir. These correlations indicate that restoration strains may be used to describe the distribution of secondary faults and fractures that are not represented in our models, providing predictive capabilities for defining fractured reservoir properties. We integrate strain and semblance with production data to evaluate these correlations at the borehole scale in the study area. We describe how tectonic strain likely enhanced permeability, directly impacting observed production trends. Our characterization of the Thirtyone reservoir demonstrates the ability to accurately predict strain distributions with geomechanical restorations where structure has been a significant factor in the development of reservoir permeability. We suggest that these methods show promise as a reservoir characterization tool for conventional and unconventional development operations.

Permeable fracture zones in the hard rocks of the geothermal reservoir at Rittershoffen, France

AbstractFluid circulation in zones of fractures are a key challenge to exploit deep geothermal heat from natural reservoir. At Rittershoffen (Upper Rhine Graben, France), two geothermal boreholes, GRT‐1 and GRT‐2, were drilled in 2012 and 2014, respectively. They targeted the local Rittershoffen normal fault, which strikes N‐S and dips westward. In this study, major natural fractures were observed in the open holes of both wells from acoustic image logs correlated with other standard geophysical logs (gamma ray, neutron porosity, and caliper). Their permeability was evaluated at the borehole scale from temperature logs, mud losses, and gas surveys. One originally permeable (OP) fracture zone was observed in the granite of GRT‐1. In GRT‐2, four OP fracture zones were observed in the granite and two in sandstones. In GRT‐2, fracture zones are composed by several fluid pathways that could explain the higher natural permeability than in GRT‐1. All OP fractures are associated with positive temperature anomaly, interpreted as circulation of hot geothermal water through the permeable fracture, or negative one, interpreted as the cooling of a porous, altered and fractured zone around the permeable fracture after drilling operations. Permeability of natural fracture oriented N170° seems to be intimately linked to the secondary mineral deposits resulting from paleocirculations. The geometrical fracture model along the wellbore suggests that the inclined trajectory of GRT‐2 increases the connection between the borehole and the nearly vertical fracture network associated to the local fault. A good characterization of zones of fractures in a targeted natural reservoir allows an optimal exploitation of geothermal resource.

Advanced DFN Models from Multi-Support Data for Underground Facilities

Fractures have a significant impact on rock mass mechanical and hydraulic properties, which is a concern for rock engineering applications like excavation or repository design, support design, slope stability and caving in mines. To address this issue, a sound description of the fracturing pattern is required. DFN models are statistical models which define the density of fractures having given geometrical properties (size and orientation) and which include an intrinsic variability term. One of the main challenging task is to combine all available data. Data remain sparse and scarce and are acquired at different scales and from different support shapes and dimension (1D, 2D). We present a 3D modelling approach combining data from borehole logs, outcrop trace maps and tunnel walls mapping. It is applied to the Äspö site in Sweden, for which a large database is available, containing tens of thousands of records. Using stereological rules and assumptions about the underlying DFN scaling model, we are able to integrate all data to define the fracturing properties from the borehole scale (ten centimeters) to the repository scale (several kilometers). An advanced DFN modeling framework is applied, accounting for fractures mechanical interactions. This model has proved to be almost universal in crystalline rocks and reproduces, with very few parameters, the scaling properties of fractures. We show that this modelling framework better reproduces observations at all available scales and yields DFN, which structure and associated properties have a better consistency with natural cases than for simple DFN approaches.

Using Time-lapse 4D Seismic to Monitor Saturation Changes in Carbonate Reservoirs

Abstract: In the past ten years, time-lapse (4D) seismic has evolved as a standard way of monitoring reservoir performance. The method is now being used as good reservoir management practice to provide evidence of saturation changes within the reservoir at field scale. 4D provides a new piece of data describing the dynamic behavior of the reservoir fluids between the wells, often limited to small scale monitoring at the borehole scale. Thus, it provides sophisticated techniques for reservoir monitoring and management relying on the integration of geological models, static and dynamic properties of the reservoir rock, and detailed production and pressure field data. While 4D seismic data has been very successful in monitoring hydrocarbon production from clastic reservoirs, this work has focused on implementing 4D time lapse to monitor saturation changes in carbonate reservoirs and it’s capability to be used as enhanced oil recovery (EOR) tool that can help in enhancing the recovery factor for the filed and help to locate new drilling to sweep more oil out of the reservoir and locate the by-pass oil. The principal goal of this research was to detect the maximum change in seismic attributes (amplitude, acoustic impedance, travel time) that could occur as a result of oil production, water and gas injection in carbonate reservoirs by using time-lapse 4D seismic.