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Second EAGE Workshop on Shales
- Conference date: 26 Apr 2010 - 28 Apr 2010
- Location: Nice, France
- ISBN: 978-94-6282-061-6
- Published: 26 April 2010
48 results
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The Shale Gas Potential of Selected Countries in Europe, Africa and the Near East
Authors J. Hill and S. WhiteleyThis paper summarises the findings of a regional study to assess the shale gas potential of selected countries in Europe, North Africa and the Near East. There has been, over the past two decades, much publicity on the shale gas revolution underway in the United States. The geology of much of Europe and North Africa is more complex and compartmentalized than that of the United States, however there are organic rich shale bearing formations present which provide the source for many of the conventional hydrocarbon accumulations across Europe and North Africa, and which could potentially provide an important gas resource. The most attractive shale bearing Formations, as in North America, tend to be Palaeozoic in age, and the most attractive of these are the Silurian shales that cover the area of interest. Locations with the highest potential include not only countries such as Poland, where shale gas exploitation is rapidly gaining momentum, but less obvious places such as Morocco and Jordan, which have significant gas demand, limited conventional resources, and favourable fiscal regimes. The paper provides both a regional overview and an individual assessment of the shale gas potential in a number of selected countries.
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Stratigraphic Heterogeneity in Shale-Gas Systems: Lessons from North America
Authors B.S. Hart and J.H.S. MacQuakerNorth American data demonstrate that shale-gas productivity is a function of a suite of economically significant mudstone properties that vary laterally and vertically at a variety of length scales. Properties of interest include porosity type and amount, permeability, mechanical properties, organic matter type and concentration, stratification style, parasequence and bed thickness, natural fracturing, etc. Many of these variables are controlled, at least in part, by the processes and environments of mudstone deposition. The mudstones of North American shale-gas plays were deposited in tectonic settings that include passive margins (e.g., Haynesville, Barnett), foreland basins (e.g., Lewis, Marcellus) and intracratonic basins (e.g., Antrim). Knowledge of depositional processes and sequence stratigraphic concepts in these systems is used to help define which basins are more attractive as exploration targets, which portions of a basin are likely to produce more gas, which stratigraphic intervals are likely to be targets for horizontal drilling, and even how core sampling should be undertaken and interpreted. Fine-grained sedimentary deposits show heterogeneity at every level, and integration of microscopic- to sequence-scale observations (e.g., SEM imagery, thin sections, core/outcrop, wireline logs, seismic) and interpretations is essential.
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A Sequence-Stratigraphic Approach to Constructing Earth Models of Shale Gas Systems
More LessShale successions are typically heterogeneous at various vertical and lateral scales. The construction of earth models (basin and reservoir models) requires a detailed analysis of rock properties within a sequence stratigraphic framework that typically integrates observations at mm- to m- to km-scales. Earth models (basin and reservoir models) that capture the appropriate level of heterogeneity allow for a systematic evaluation of shale gas resources. Here we present an earth model of the Mowry Shale Formation in the Powder River Basin, WY to illustrate the workflows and simulation results.
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Can Conventional Basin Modelling Predict Gas Shale Occurrence? A Case Study from the Fort Worth Basin, TX (USA).
Authors F. Lorant and D.M. JarvieThis paper describes a case study from the Fort Worth Basin (USA), where the occurrence of residual gas in the Barnett shale was analyzed using standard basin modeling. The aim of this work was to determine to what extent conventional petroleum system simulation approaches can be applied to an unconventional system like gas shale. A sensitivity analysis was thus performed, to quantify the dependency of the residual mass of gas in the source rock at present day, on parameters involved in the generalized Darcy flow model, i.e., permeability, relative permeability, capillary pressure and adsorption threshold parameters. We found that gas retention in the source rock was mostly controlled by the gas relative permeability, and especially the gas expulsion saturation (i.e., ‘Satex’ value). High capillary pressure in the shale favours gas expulsion, however this process remains limited compared to relative permeability and permeability effects. Surprisingly, adsorption threshold values had nearly no effect on the residual mass of gas: adsorption was indeed largely compensated by the Satex effect. These results demonstrate that conventional basin modelling can reproduce the occurrence of a gas shale play, by adjusting at least gas relative permeability parameters in the source rock, especially the Satex value.
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Strength Prediction and Evolution in Shales
Authors D.N. Dewhurst, J. Sarout, C. Delle Piane, A.F. Siggins, M.D. Raven and U. KuilaShale strength is an important parameter for wellbore stability, trap integrity, hydrofracturing and various types of subsurface geological storage. However, strength of shales is not well constrained due to limited available data. This study is in two parts: 1. Empirical correlations between physical and petrophysical properties of a range of shales from basins worldwide to static and dynamic elastic properties. Here, good correlations were found between porosity and normalised cation exchange capacity (CEC) to cohesion and unconfined compressive strength. CEC normalised to density proved a useful parameter in these empirical correlations. Friction was harder to derive an empirical relationship for, although a complex relationship was found with good correlation although of dubious statistical merit. 2. Evolution of static and dynamic mechanical properties with compaction and diagenesis. Investigations of a sequence of shales from a well in the Officer Basin in Western Australia and showed significant increases in static mechanical properties with chemical compaction likely the dominant mechanism. P- and S-wave velocities both parallel and normal to bedding also increase with depth and the anisotropy of velocity decreases. While these results are somewhat intuitive, this is believed to be the first laboratory-based study to show such a result.
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From Mud to Shale: Quartz Cementation During Burial of Late Cretaceous Mudstones, Offshore Norway
Authors B. Thyberg and J. JahrenTwo different quartz cement morphologies have been identified in originally smectite-rich Late Cretaceous mudstones. 1) Extremely fine-grained micro-pore-filling quartz (sub-micron to 1-3 µm) found as spherical discrete grains or as part of short chains/clusters of several inter-connected micro-quartz crystals. This type is also typically inter-grown with clay crystals and found embedded in the fine-grained illitized clay matrix below 2500 m burial (80-85 ºC). 2) Quartz platelets oriented normal to the overburden as laterally extensive sheets with typical irregular or patchy development. The quartz platelets originate as extremely thin flakes that evolve into well-developed patchy continuous quartz cement as identified at 4300 m/150 ºC. The identified quartz cement were most likely sourced by silica released from the dissolution of smectite and precipitation of illite-smectite and illite due to evaluated silica super-saturation in the system. The observed inter-connected micro-quartz crystals are associated with a sudden Vp-velocity increase reflecting an increase in the mudrock stiffening interpreted to be related to pervasive micro-quartz networks and aggregate formation. The quartz platelets will reinforce and further cement together the micro-quartz networks and aggregates during burial.
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Triaxial Simulation of Compaction Processes in Mudrocks
Authors L.M. Duffy and A.C. AplinMudstone compaction is generally viewed as a combination of mechanical and chemical processes, in which porosity is lost first as a result of increasing effective stress and then due to mineralogical changes. This study sought to test this concept by subjecting natural mudstone to a series of triaxial experiments. These were carried out under a range of effective stresses up to 50MPa, at temperatures up to 150oC and in a range of fluid chemistries designed to investigate the relative roles of different components of the burial environment. Two longer duration triaxial tests ran for 57 days at a maximum effective stress of 50MPa. One used K-rich pore fluids and a temperature of 150oC which produced an increase in grain density with a decrease in volume, pore size and porosity. These changes occurred without mineralogical transformation. However, the other was carried out at 25oC using Na-rich fluid and did not significantly, permanently compact the mudstone. It remained at a porosity retained from its natural consolidation at <2km despite the application of 50MPa effective stress. The effects of cation exchange with potassium and temperature appear important factors to understand when attempting to model natural diagenetic processes in the laboratory.
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Peeling of Sheared Mudstones: Insights into the Smectite to Illite Transformation
By E. CascielloThe microstructural characteristics of a shear zone developed in Plio-Pleistocene mudstones of the Southern Apennines have been analysed by means of XRD, SEM, optical microscope observation and a consolidation test. XRD analyses indicate that the wall rock contains mixed layer illite/smectite while the fault gauge contains illite only. The distribution patterns of smectitic and illitic mudstones is analysed thanks to a simple peeling technique that allows observation with optical microscope and SEM. The consolidation test provides indications on the depth at which deformation occurred.
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On the Constitutive Equation of Elastic Anisotropy of Shales
By L. DurantiExperimental work on shales has evolved to the extent that some first order relationships governing the elastic constants and their evolution with stress and depth can be sketched. These relationships are reviewd in this paper along with the experimental evidence.
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Elastic Properties of Shales: Influence of Stress and Anisotropy
Authors C. Delle Piane, D. Dewhurst, T. Siggins and M. RavenWe used undrained multi-stage triaxial tests to evaluate how the ultrasonic wave velocities and their anisotropy changed with increasing isotropic and differential stress conditions. In addition, the impact of stress orientation with respect to fabric orientation was evaluated. An array of ultrasonic transducers allowed to measure five independent wave velocities which were used to calculate the elastic properties of the shale. Results indicate that in this shale P- and S-wave velocities vary with stress in a different manner dependent on the maximum stress orientation with respect to the fabric orientation. Where the maximum stress is normal to bedding, Vpv and Vs1 increase monotonically with increasing effective stress. However Vph and Vsh decrease during individual loading stages but increase from stage to stage as confining pressure increases. The reverse occurs when the microfabric is parallel to the maximum principal stress. Where the maximum stress is bedding normal, velocity anisotropy decreases as differential stress increases; when maximum stress is fabric parallel, anisotropy increases. Intrinsic anisotropy is related to the initial composition and fabric of the sediment, while changes in elastic anisotropy result from the applied stresses, their orientation to the rock fabric and the degree of stress anisotropy
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Velocity Anisotropy of a Shallow Mudstone Core
Authors N.H. Mondol, L. Grande, E. Aker, T. Berre, T. Ørbech, K. Duffaut, J. Jahren and K. BjørlykkeMudstones and shales are a major component of most sedimentary basins and are anisotropic because of the alignment of plate-line clay minerals. The results show that the shallow mudstone is weakly anisotropic with respect to P-wave anisotropy (Thomsen’s parameter ε) on the order of 20% but strongly anisotropic for S-wave propagation (Thomsen’s parameter γ) on an order of 64% at higher stress. The anisotropy parameter δ is observed as maximum as 42%. The magnitude of P-wave anisotropy (ε) seems to increase with increasing effective stress or depth of burial. The other anisotropy parameters (γ and δ) also increase with increasing stress upto certain stress levels (about 12 MPa mean effective stress) and than decrease gradually with increasing mean effective stress. Factors such as stress induced as well as alignment of plate-like clay minerals may causing the different anisotropic behavior for γ and δ compared to ε where shear wave polarization may play an important role. The anisotropic behavior found in the shallow mudstone core may impact seismic imaging, AVO analysis, time-depth calculations and well to seismic tie of sonic log data of deviated wells.
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Anisotropic Mechanical Response of a Shale
Authors L. Laloui, S. Salager, M. Nuth and P. MarschallThe purpose of the study is to characterize the main features of the anisotropic mechanical behaviour of a shale (Opalinus Clay), and to identify an anisotropic constitutive framework adapted to the response of the material under mechanical perturbations. Such a constitutive model is required for the simulation of triaxial tests which were done on OC samples. Firstly, the large quantity of available laboratory tests which characterize the mechanical response of OC has been analyzed. The test series provide clear evidence for anisotropic mechanical behaviour of Opalinus Clay. It appears that the stress history and the micro-structure of the material induce a typical response of the material which is more overconsolidated (higher rigidity, less ductile behaviour…) for loading direction parallel to the bedding plane than perpendicular to it. Concerning numerical investigations, the capabilities of the model of Hujeux have been assessed in reproducing the anisotropic features of behaviour of OC. The constitutive model uses the theory of multi-mechanisms plasticity. Two fundamental observations account for the adequacy of the chosen constitutive framework: the elastic moduli depend on the direction of shearing, and induced anisotropy will affect the way the material hardens or softens depending on the angle of shearing.
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Elastic Wave Attenuation in a Clay Rich Shale
Authors A.F. Siggins and D.N. DewhurstSpectral ratio methods are used to investigate the attenuation of p-waves in a clay rich shale as a function of confining pressure. A generalised standard linear solid (GSLS) model is then fitted to the data. The attenuation of the fast axis p-wave is found to be relatively indepenent of confining pressure and is in good agreement with the GSLS model.
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Computational Rock Physics for Shales
By A. NurThe emerging imaging and computing technology is especially effective for gas-shale where the knowledge and understanding of the internal pore architecture (down to 3 nanometer scale) is crucial for determining connected vs. unconnected porosity, TOC distribution and maturity, pore size distribution, mineralogy, sample-scale heterogeneities, computing 2 phase flow, and Interrelate all properties on same sample.
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Understanding Geophysical Responses of Shale Gas Plays
Authors Y. Zhu, A. Martinez, E. Liu, C. Harris, S. Xu, M. Payne and M. TerrellUnconventional resources such as shale gas are becoming increasingly important exploration and production targets. However, the geophysical characterization of these unconventional reservoirs remains challenging because of limited understanding of reservoir properties such as total organic carbon (TOC). As a significantly important component of the rock, organic matter has unique features (e.g., being soft, resistive, and with non-zero shear modulus) that influence effective elastic properties differently than effective electrical properties, thus providing the basis for an integrated geophysical analysis of shale gas.
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Looking for Gas in All the Tight Places
By T.L. DavisA case history of detecting "sweet spots" associated with zones of high permeability in a tight gas reservoir using multicomponent seismology.
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Hydraulic Fracture Optimization Using 3D Seismic Data
Authors F.D. Gray, P.F. Anderson, W.N. Goodway and J.D. LogelWe describe a method for the estimation of rock strength and stress between wells using 3D seismic data. The method is demonstrated on the Colorado Shale Formation in Alberta, Canada. The application of the method to these data clearly shows that both rock strength and stress can vary significantly over very short distances. Therefore, it is recommended that this method be used wherever possible to optimize hydraulic fracturing in unconventional reservoirs.
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Azimuthal Velocity Analysis and Shale Gas Reservoirs
More LessShale gas reservoirs have become important hydrocarbon targets for oil and gas companies. Fractures and stress fields play important roles in the development of shale gas reservoirs. New seismic analysis methods enable geoscientists to map fracture patterns and associated permeability changes, allowing E&P operators to better target highly productive zones within these tight, heterogeneous reservoirs. Horizontal transverse isotropy (HTI) is an important issue for shale gas reservoirs and can be an effect of such things as vertical aligned fractures or unequal horizontal stresses. Azimuthal velocity analysis allows the measurement of HTI effects in wide azimuth seismic data and the determination of important azimuthal velocity anisotropy attributes. Calibration of the anisotropy attributes with well data can provide information regarding fracture density and orientation as well as horizontal stresses, thereby allowing geoscientists to predict sweet spots in shale gas reservoirs.
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Experimental Determination of the Osmotic Properties of Chemically Sensitive Shales
Authors J. Sarout and E. DetournayLaboratory experiments are reported that were aimed at assessing the physicochemical interactions occurring between chemically sensitive rocks and aqueous fluids. It is principally motivated by the need to assess the capacity of stabilizing a borehole drilled in a reactive shale formation by increasing the salt concentration of the water-based drilling mud. By analyzing the experiments within the framework of the Biot theory of poroelasticity, extended to include physico-chemical interactions, and by studying the parameters that are influencing the fluid pressure response in the downstream reservoir, we show the conditions under which determination of R from the maximum pore pressure drop is virtually independent of the specific experimental setup. In fact, we show that the equivalence of R and the membrane efficiency hinges on the existence of an intermediate time asymptotic solution of the experiment, linked to a separation of time scales. A combined experimental and theoretical workflow dedicated to the assessment of shale/drilling fluid interactions has been developed in order to improve: (i) the experimental setup used in the laboratory; (ii) the experimental protocol for running the pressure transmission stages; and (iii) the quantitative interpretation of the output experimental data in terms of well-defined reactivity parameters.
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Improved Calibration of Borehole Stability Models in Shales Using Hollow Cylinder Laboratory Tests
Authors O.M. Nes, J.F. Stenebråten and E. FjærTo improve the understanding of behavior related to the borehole geometry in shales, and to generate better input data to borehole stability simulators to be used when estimating the stable mud weight window, we have developed an experimental methodology whereby we perform rock mechanical laboratory tests on various shales in a hollow cylinder geometry. We present our methodology, including both laboratory measurements, how such data and other data are fed into our borehole stability simulator, as well as results for specific cases. These tests allow for a better understanding of failure mechanisms causing borehole instabilities and providing calibration data to borehole stability models. When integrated into proper borehole stability simulators it thus represents an applicable tool for attaining improved drilling performance while drilling through shales.
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Well Log and Seismically Derived Impedance of Clay-Rocks for Higher Resolution of Pore Pressure Prediction
Authors S.B. Nowak and P.D. HeppardIn this paper we discuss how acoustic impedance can be utilized for pore pressure prediction. Acoustic impedance, the product of velocity and density, of normally pressured shales behaves in a predictable manner of increasing impedance with increasing burial depth as shale compacts. Overpressure in clay rocks is noted by a deviation from the normal compaction trend to lower values. The minerology of clay rocks affects the impedance in a manner similar to other log responses of velocity, resistivity and density and must be considered when evaluating for pore pressure. Previous applications of seismically derived impedance for pore pressure have used it to modify migration-derived velocities to improve resolution. In this application we use a calibrated inversion of seismic data for shale impedance and directly convert to pore pressure. This process reduces the effects from other rock types, improving resolution and potentially accuracy. This is in contrast with seismic migration velocities which include an average property of all rocks over relatively thick sections. This negatively affects pore pressure predictions since almost all pore pressure calculations are based on the predictability of shale and clay rocks, not sandstone, siltstone, marl, limestone and other rock types.
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Experimental Simulation of 4D Overburden Effects Associated with Depletion of or Injection into a Subsurface Reservoir
Authors R.M. Holt and J.F. StenebråtenIn this presentation we show results of laboratory experiments on compacted brine-saturated clay specimens experiencing an initial stress state and stress changes representative of those occurring in situ during depletion of or injection into an underlying reservoir. The results can be used to assess expected 4D response in realistic field cases, to evaluate various 4D attributes, and also possibly to help quantify stress changes from 4D data.
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The Effect of Intra-Reservoir Shales on Effective Stress Sensitivity
Authors Y. HajNasser and C. MacBethIn most clastic reservoirs experiencing pressure depletion, the sands in the reservoir naturally compact. As a consequence, the much lower permeability reservoir shales may experience extension. This extension is counteracted to some degree by pressure equilibration of the shale. The effective seismic response of the reservoir interval may thus be a mix of both hardening and softening reservoir components, depending on the balance of these phenomena. This effect is predicted to alter the overall stress sensitivity of the seismic properties from that anticipated for a homogeneous, fully connected reservoir interval. However, the final resultant response depends on the time period over which this effect is observed. Numerical computation using simplified geological models indicates shales of 1m to 10m thickness should be taken into account when quantitatively assessing the 4D seismic signature from frequently shot time-lapse surveys with a periodicity of 3 to 12 months, whilst 5 to 10m thick shales could impact conventional 4D seismic surveys shot over 5 to 10 years. These conclusions are strongly affected by the mechanical and transport properties of the intra-reservoir shales, their thickness and distribution, and are hence also a function of the depositional environment.
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Ten Years of Microseismic Mapping of Shale Gas Completions: Lessons Learned
By R.J. ZinnoMicroseismic monitoring has played a critical role in the success of shale gas production in North America over the last ten years. Several surveys spanning that period, including the first survey in a shale gas field, describe the evolution of that success. These case histories illustrate important lessons learned about influence of fine geologic structures on the fracture behaviour of these reservoirs during stimulation. These stimulation mapping examples chronicle the evolution of modern completion techniques to address and exploit these reservoir complexities.
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Optimizing Drilling and Completions in a Gas Shale - Microseismic Monitoring in North America
By C. NealeCommercially driven development of oil and gas shale reservoirs usually requires hydraulic fracture stimulation to create induced fractures that connect naturally-occurring, hydrocarbon-filled fracture networks with the producing wellbore. The use of microseismic monitoring during hydraulic stimulation has become a standard practice in the development of most North American unconventional resource plays, providing rapid and significant improvements in completion efficiency. The reservoir parameters determined from monitoring include the local orientation of maximum stress, the volume of reservoir contacted by the induced fractures and reactivated natural fractures, and the dimensions of the induced fracture network on a stage by stage basis. This paper will discuss case histories from several US gas shale basins, presenting the development issues being addressed by the stimulation monitoring and how the microseismic monitoring provided direct answers to these problems. Also discussed is the use of temporary surface and permanent near-surface geophone arrays for data acquisition to expand the range of monitoring applications beyond those available from traditional borehole-located geophone array monitoring.
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Monitoring the Hydraulic Stimulation and Production of an Unconventional Reservoir Using 4D 3C Seismic
Authors J.W.G. Atkinson, J. Logel, E. Andersen, K. Wikel and D. GrayIn order to determine optimal well spacing, depletion radii, and vertical extent of the stimulated rock volume in an unconventional shale gas reservoir in the Western Canadian Sedimentary Basin, an advanced multicomponent, time-lapse survey was shot by Talisman Energy in 2008 along with microseismic (surface, water well, and downhole) surveys and a multicomponent VSP. Four seismic surveys were conducted before, during and after hydraulic fracturing of multiple horizontal wells. The purpose of the time-lapse data is to determine if unconventional production and hydraulic fracturing can be delineated using multicomponent seismic methods. Time-lapse work is relatively novel in the unconventional realm, and large amplitude/time changes of the magnitude seen in offshore conventional and many heavy oil reservoirs are not expected. This emphasizes the need for maintenance of quality control measures through the cross-equalization process. Preliminary results on the cross-equalized PP surveys indicate amplitude/time changes coincident with wellbore trajectory. Though clear evidence of time-lapse changes exists, work to understand these results continues.
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Microseismic Imaging of Hydraulic Fracture Complexity in Shale Gas Reservoirs
Authors S.C. Maxwell, C. Cipolla and M. MackMicroseismic imaging of shale gas hydraulic fracture treatments has shown that the stimulations are often complex, resulting from interaction of the injection with pre-existing natural fractures. In this paper, various case studies will be shown contrasting shale gas stimulations with tight gas hydraulic fracture treatments. Integration of microseismic images with reservoir characterization and geomechanical factors is important to understand the mechanisms controlling the complexity and their variation through the reservoir. Microseismic images are also valuable to characterize the success of the planned stimulation, which is important to understand the well performance and improve future stimulation designs and completion strategies.
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Innovative Modeling Techniques to Quantify Fracture Characteristics, Reservoir Properties, & Well Performance in Shales
Authors C.D. Jenkins, M.A. Miller, J.D. Walls and R.R. RaiIn order to characterize reservoir and hydraulic fracture properties using well performance data in shale gas reservoirs, it is essential to apply an appropriate workflow and advanced modeling techniques. The workflow should begin with a review of the well data followed by the use of analytical methods to identify different types of well behavior and to form hypotheses about the various production mechanisms at work. Numerical modeling can then proceed, first with scoping models and then with detailed numerical models to conduct production forecasting and completion optimization sensitivities. A useful tool for this detailed modeling is finite-element simulation which places a large number of closely-spaced nodes near the hydraulic fractures. This extremely fine-scale gridding captures high-resolution pressure transients that dominate well behavior during the first few years of production. The results of this work provide key insights into reservoir and fracture properties, and can be used to optimize production forecasts, well placements, lateral lengths, and completion techniques.
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Evaluation and Influence of Structural Trends from Magnetic and Gravity Data in the Texas-Louisiana Haynesville Play
Authors S.J. Campbell, G. Thompson, R. Inden, W. Pearson, T. Kerrane and J.D. FairheadA number of individual elements need to be present to produce a viable hydrocarbon system in both conventional and non-conventional shale plays. Key to this is the influence of both regional and localised fault and fracture patterns, and examples of these and their correlation with production from the Texas-Louisiana Haynesville area are presented. This paper demonstrates how powerful a tool high resolution gravity and magnetic data are in the identification of structural trends and fracture patterns in the Haynesville area. Analysis of these data helps define the trends that strongly influence the production, permeability and depositional trends in the Haynesville and other key stratigraphic units in the basin. Understanding of these trends, their inter-relationship and their influence on production can help focus an exploration programme.
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Limits to Hydrocarbon Stability in Deep Basins: Evidence from Stable Isotope Reversals and Noble Gas Geochemistry
Authors C.D. Laughrey and R.C. BurrussWe report reversals of both carbon and hydrogen isotopic compositions in natural gases in a deep sedimentary basin (Appalachian basin, eastern USA). The isotopic and molecular compositions together with unique geochemical properties of the source organic matter allow us to seperate mixing and source contributions to the gases so that we can identify trends due to Raleigh fractionation during hydrocarbon destruction by redox reactions. Data from noble gas geochemistry and the isotope geochemistry of carbon dioxide, nitrogen, and hydrogen sulfide in the gases support our arguements. Rapid development and exploitation of shale gas and other unconventional reservoirs has begun to encounter gases with partial to complete carbon isotope reversals. Our interpretation of the origin of reversals due to destruction of higher hydrocarbons at high thermal maturities in sedimentary basins may place constraints on the potential volume of resource from these types of gas accumulations.
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Application of Whole-Rock Elemental Data in Shale-Gas Development: An Example from the Jurassic Haynesville Formation
Authors D.R. Spain, M.C. Dix, J.L. Sano, K.T. Ratcliffe, S.N. Hughes, N.G. Casarta and D. BullerThe latest technologies for collection of elemental data from rocks are VERY BRIEFLY reviewed (and not emphasized). The applications of elemental data for shale gas development are then explained with reference to a large data base from eight North American shale gas formations. Finally, a specific example of how elemental data can be integrated with conventional data, and used throughout a drilling program, is given with the Jurassic Haynesville Formation as a case study.
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Experimentally-Derived Mechanical and Flow Properties of Mudstones
Authors J. Schneider, C.S. Peets, P.B. Flemings, R.J. Day-Stirrat and J.T. GermaineWe developed a systematic approach to predict mudstone compressibility and permeability as a function of composition. We prepared mixtures of natural Boston Blue Clay (BBC) and synthetic silt in four different proportions and resedimented these mixtures. From uniaxial consolidation tests we show that compressibility and permeability vary systematically with silt fraction. Compressibility linearly decreases with increasing silt fraction whereas permeability exponentially increases with increasing silt fraction. Normalizing the flow behavior by using effective void ratio allows the ability to predict permeability if porosity and composition are known.
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Metre-scale Effective Flow Properties of Heterogeneous Fine-Grained Sediments
Authors K.D. Kurtev, M. Drews, J. Ma and A.C. AplinThe evaluation of the effective flow properties of heterogeneous shales are key constraints for hydrocarbon and CO2 leakage evaluation, as well as for hydrocarbon migration through source rocks and tight reservoirs. Here, we demonstrate an approach to determine effective permeability and Capillary Enter Pressure based on capturing and stochastically simulating the natural variability of shale texture. It is shown that the shale texture or spatial variability of lithology is closely related to connectivity and thus to the anisotropy of effective flow properties. We believe that the proposed approach has additional potential for the estimation of the effective relative permeability of shale volumes 1m3 and upwards.
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Effects of Clay Content on Porosity Versus Depth Trends
Authors E. Fjær, A.E. Lothe and Ø. SyltaBased on a calibrated model for porosity versus depth in sedimentary basins, the impact of clay content is described. The model is based on rock mechanical principles, and describe porosity as a function of pore compaction and effective stress. The results show that local clay content affect both the initial (sea floor) porosity and the resistance against compaction while the average clay content in the overburden affects the effective stress. Such models may be applicable for pore pressure prediction as well as modelling of hydrocarbon migration, basin modelling and seismic velocity inversion.
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Empirical Approach for Evaluation of Compressive Strength of Shale
Authors M.R. Asef and M. FarrokhrouzA sound knowledge regarding the strength and stiffness properties of rock material could significantly improve engineering geological assessments. Shales are known as the most problematic rock material worldwide. Uniaxial compressive strength UCS is an essential input parameter for development of almost any engineering design. However, appropriate core specimen for measurement of UCS in the lab is often a real dilemma. Accordingly, extensive attempts have been made for strength estimation based on other parameters. In this research, an empirical equation is suggested for estimating UCS of shale based on Young’s modulus and porosity. This equation was achieved based on statistical analysis of lab experiments obtained over a wide range of geographical locations. A further attempt was made to describe mathematical meaning of the statistical results based on theory poroelasticity. Accordingly, at low porosity values both Young’s modulus and porosity significantly contribute in prediction of the UCS. This was attributed to poroelastic behavior of shale under these conditions. At high porosity values, however, E was the dominant parameter. One of the advantages of this research is that suggested equation is independent of the geographical location, while it is based on two input parameters Young’s modulus, and porosity.
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Bound Water in Shale: Molecular Scale Simulations and Experimental Indications
Authors M.I. Kolstø, D. Potyondy and R.M. HoltIn this paper we show through a molecular scale mechanics simulation that structural order of water near charged surfaces results in a finite shear stiffness of the water phase. This interpretation is supported with experimental data on compacted claystone. We illustrate how the results may be applied in a rock physics model for mudstone / shale.
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Effective Laboratory Measurements of Low Permeability of Shales
Authors P.F. Boulin, P. Bretonnier and E. BemerAssessing shale permeability is a key issue to ensure its efficiency as a reservoir cap rock or its relevancy as a geological barrier in radioactive waste disposals. Clay materials have such a low permeability that conventional experiments cannot be performed. Most of the authors dealing with the characterisation of shale use a transitional method called pulse decay. The experiment presented here is based on a steady state method. It appears to be faster and more reliable than any other permeability techniques. Permeabilities from 0.2 to 200 nD (2 10-22 to 2 10-19 m2) can be estimated in less than one day.
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Active and Passive Seismic Monitoring of Shales Under Triaxial Stress Conditions in the Laboratory
Authors J. Sarout, A. Ougier-Simonin, Y. Guéguen and A. SchubnelLaboratory experiments are reported that were aimed at estimating various rock physics parameters that are of importance in geophysics. Several triaxial deformation experiments on shale specimens from two offshore oil field reservoirs have been performed. Three main parameters were continuously monitored during the deformation process: (i) gas permeability; (ii) local strains in various directions; (iii) longitudinal and shear wave velocities for various directions of propagation; and (iv) micro-seismic events induced by the triaxial stress loading. The wave velocity surveys performed at various stages along the loading path allowed for the estimation and the update of the elastic wave velocity field. The strain data allowed for the update of the wave travel path length along the stress loading. This procedure ensured an accurate and reliable localization of the micro-seismic events that occurred between consecutive surveys. It also allowed for the estimation of the evolution of shale anisotropy under traixial stress loading.
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Control of Geomechanical instability of Shale based on Optimized Well Engineering Decision
Authors M Farrokhrouz and M.R. AsefShale instability is essentially driven by changes in stress and/or chemical alteration. However, sometimes less attention may be paid to geochemical processes. In addition, some well engineering approaches may inevitably facilitate geochemical alterations. An appropriate decision may be more difficult if shale is observed as interbred layers in a carbonate reservoir (rather than as a cap rock). In this research an exceptional approach was chosen to identify geochemical processes that induced geomechanical instability in a gas reservoir with shale interbeds in the South of Iran. Nevertheless, the problem and potential solutions were worked out corresponding to the conceptual engineering geological skills. The results showed that excessive water and HCL acid (traditionally used for well stimulation) in contact with shale interbeds could have significantly contributed in plugging of the well. Site investigations revealed that the amount of excessive (unwanted) water, to a large extent depends on the gas production rate. A systematic analysis of geochemical processes at different production rates was conducted. Mineral precipitation/dissolution of shale formation was simulated accordingly. Corresponding geomechanical interpretations were considered as key points to make an appropriate decision based on economic production rate and the likely well engineering problems.
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An Alternative to Hydrofracture
By G.D. CouplesHydrofracturing is an inprobable process in basins. Instead, dilational, shear-related deformations are predicted under the conditions that can normally be achieved. Such dilational responses explain the observed pressure profiles and the outcrop-based observations.
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Numerical Study of Consolidation Effect on Time Delayed Borehole Stability During Underbalanced Drilling in Shale
More LessTime delayed mechanical borehole stability is mostly depending on the pore pressure consolidation process. Establishment of pore pressure equilibrium in shale is a time dependent process which is characterized by shale intrinsic properties. In shale, water movement is greatly restricted by the low permeability of shale which may cause pore pressure storage and lead to redistribution of borehole stresses. To prevent wellbore instability problems, accurate predictions of stresses and deformations around the wellbore are essential, particularly when drilling in underbalance in shale. Using an adequate constitutive model for shale is crucial in obtaining accurate predictions of the stress changes and deformations. Recent research shows that several mechanisms contribute to shale instability, including swelling, pressure diffusion, plasticity, anisotropy, capillary effects, osmosis and physcio- chemical alteration. It is clear that it may be impossible to consider all features of shales in one model. However, an improved understanding of the behaviour of shales during UBD will enable the main features to be included and facilitate more rational predictions. This study was developed numerical material model. The model is enabled to predict borehole collapse risk with the impact of time delayed consolidation effect. The generality of this study is to enhance knowledge of downhole
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Overpressure Prediction based on a Rock Physics Model for Shales
By A. NogeitzigThe stress sensitivity of seismic velocities is used for overpressure prediction. A software code calibrates sonic data with predicted velocities and returns an estimation of pressure, smectite illitisation (in mineral fraction), temperature, conductivity and porosity with depth. The results show good agree of predictions with measured data, as long as geological/lithological input information is reliable.
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Passive Seismic Monitoring to Optimize Hydraulic Fracturing Treatments: Lessons Learned from our American Cousins
Authors J. Le Calvez, S. Maxwell and A. MartinezNorth American shale-gas recovery efforts are quite large, while the extent of such unconventional gas reserves in Europe is largely unknown. Some tests of gas shale formations have recently been carried out with good success in various basins (e.g., Germany’s Lower Saxony, Vienna Basin, southern Sweden, etc.) The development of Europe’s gas resources will take years and may benefit from lessons learned in North America. Firstly production from unconventional shale formations (e.g., Barnett, Fayetteville, Marcellus, Woodford, etc.) has been enabled by modern well log evaluation techniques and completion methods. These are particularly important since stress anisotropy strongly influences fracture system development. Secondly, it is critical to monitor the initiation and evolution of hydraulically-induced fracture systems. Currently almost all predictive models used by reservoir and production engineers to estimate recovery in stimulated wells are based on assumptions that naturally lead to oversimplified fracture geometry. Microseismic monitoring enables reservoir engineers and geoscientists to understand the development of hydraulically-induced fracture systems as well as naturally pre-existing fracture networks in four dimensions.
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