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Summary The current state-of-the-art technology for in-situ stress measurements involves an integrated approach that combines borehole breakout observations, drilling-induced tensile fractures, and hydraulic fracturing tests (i.e., “mini-fracs”). This methodology has achieved wide application in the oil and gas industry but has several limitations that often prevent successful in-situ stress measurements. One major limitation is that breakouts do not appear in all boreholes and are generally only a natural occurrence that cannot easily be controlled. Because borehole breakouts are used to directly measure the maximum horizontal in-situ stress magnitude, the absence of borehole breakouts presents a major data gap for in-situ stress measurements. In response to this data gap, a new US Department of Energy (US DOE)-sponsored thermal breakout technology that will provide a method for thermally inducing borehole breakouts and allow the consistent measurement of the maximum horizontal stress magnitude is currently in development. This thermal breakout technology involves heating the borehole and increasing the thermoelastic compressive stress in the rock until a breakout develops, which can be directly correlated to the maximum horizontal stress magnitude. The first step in this project was an analytical modeling study of the thermal breakout process. Based on the Kirsch solution (Kirsch 1898), a deterministic and statistical analysis was performed on the pertinent parameters that influence the maximum horizontal stress calculation. As a result of the analysis, the findings indicate that the thermal breakout technology is feasible and provides improved accuracy and/or an enhanced ability to measure the maximum horizontal stress. Future work as part of this US DOE-sponsored project includes additional validation through more detailed numerical modeling, laboratory testing, and field testing of the thermal breakout technology.

A theory for laser-driven electron dynamics and high-harmonic generation in bulk solids with two lattice sites per unit cell of arbitrary dimension is formulated. In tight-binding approximation, such solids can be described by $2\times 2$ Bloch-Hamiltonians. Our theory is able to fully capture topological effects in high-harmonic generation by such systems because no simplifications beyond tight-binding, dipole approximation, and negligible depletion of the valence band are made. An explicit, analytical expression for the electron velocity is given. Exemplarily, the theory is applied to the Su-Schrieffer-Heeger chain and the Haldane model in strong laser fields., 14 pages, 6 figures, RevTeX

Creation of an Enhanced Geothermal System relies on stimulation of fracture permeability through self-propping shear failure that creates a complex fracture network with high surface area for efficient heat transfer. In 2010, shear stimulation was carried out in well 27-15 at Desert Peak geothermal field, Nevada, by injecting cold water at pressure less than the minimum principal stress. An order-of-magnitude improvement in well injectivity was recorded. Here, we describe a numerical model that accounts for injection-induced stress changes and permeability enhancement during this stimulation. We use the coupled thermo-hydrological–mechanical simulator FEHM to (i) construct a wellbore model for non-steady bottom-hole temperature and pressure conditions during the injection, and (ii) apply these pressures and temperatures as a source term in a numerical model of the stimulation. A Mohr–Coulomb failure criterion and empirical fracture permeability is developed to describe permeability evolution of the fractured rock. The numerical model is calibrated using laboratory measurements of material properties on representative core samples and wellhead records of injection pressure and mass flow during the shear stimulation. The model captures both the absence of stimulation at low wellhead pressure (WHP ≤1.7 and ≤2.4 MPa) as well as the timing and magnitude of injectivity rise at medium WHP (3.1 MPa). Results indicate that thermoelastic effects near the wellbore and the associated non-local stresses further from the well combine to propagate a failure front away from the injection well. Elevated WHP promotes failure, increases the injection rate, and cools the wellbore; however, as the overpressure drops off with distance, thermal and non-local stresses play an ongoing role in promoting shear failure at increasing distance from the well.

In this paper, we review a suite of techniques for determination of in situ stress orientation and magnitude in deep wells and boreholes. As these techniques can be utilized in both vertical and highly deviated wells, they have had extensive application in the petroleum industry where knowledge of stress orientation and magnitude at depth is important for addressing a wide range of problems. The techniques we have developed for estimation of the maximum horizontal principal stress, SHmax; make extensive use of observations of non-catastrophic failures of the wellbore wall—both compressive failures (breakouts) and tensile failures (drillinginduced tensile fractures) as well as the stress perturbations associated with slip on faults cutting through the wellbore. The widespread use of wellbore imaging in the petroleum industry has been a critical development that makes utilization of these techniques possible. In addition to reviewing the theoretical basis for these techniques, we present case studies derived from oil and gas fields in different parts of the world. These case studies document the facts that the techniques described here yield (i) consistent stress orientations and magnitudes over appreciable depth ranges within and between wells in a given field (thus indicating that the techniques are independent of formation properties), (ii) stress magnitudes that are consistent with absolute and relative stress magnitudes predicted by Anderson and Coulomb faulting theories, (iii) stress orientations and relative magnitudes that are consistent with regional stress indicators and tectonics observed with other techniques at much larger scales and (iv) sufficiently wellconstrained estimates of the full stress tensor that are useful in application to engineering problems such as wellbore stability. r 2003 Elsevier Ltd. All rights reserved.

Relationships between porosity and shear modulus are applied to logs recorded in the Miocene Upper Terminal formation of the Wilmington Field, CA. to predict porosity from shear-wave velocity data recorded through casing using a dipole sonic logging tool. A relationship based on a modified Hashin-Shtrikman lower bound, appropriate for the unconsolidated nature of the formation, allows determination of porosity from the shear modulus. The results are similar to those obtained using standard log analysis in sands. Standard logs predict higher porosities in smectite-bearing wackes because of the inclusion in the standard analysis of bound water or micro-porosity in the clays which is not included in the porosity value derived from the shear-wave velocity.

A comprehensive geomechanical study was carried out to optimize stimulation for a frac‐ tured tight gas reservoir in the northwest Tarim Basin. Conventional gel fracturing and acid‐ izing operations carried out in the field previously failed to yield the expected productivity. The objective of this study was to assess the effectiveness of slickwater or low-viscosity stim‐ ulation of natural fractures by shear slippage, creating a conductive, complex fracture net‐ work. This type of stimulation is proven to successfully exploit shale gas resources in many fields in the United States. A field-scale geomechanical model was built using core, well log, drilling data and experien‐ ces characterizing the in-situ stress, pore pressure and rock mechanical properties in both overburden and reservoir sections. Borehole image data collected in three offset wells were used to characterize the in-situ natural fracture system in the reservoir. The pressure re‐ quired to stimulate the natural fracture systems by shear slippage in the current stress field was predicted. The injection of low-viscosity slickwater was simulated and the resulting shape of the stimulated reservoir volume was predicted using a dual-porosity, dual-permea‐ bility finite-difference flow simulator with anisotropic, pressure-sensitive reservoir proper‐ ties. A hydraulic fracturing design and evaluation simulator was used to model the geometry and conductivity of the principal hydraulic fracture filled with proppant. Fracture growth in the presence of the lithology-based stress contrast and rock properties was com‐ puted, taking into account leakage of the injected fluid into the stimulated reservoir volume © 2013 Gui et al.; licensee InTech. This is an open access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. predicted previously by reservoir simulation. It was found that four-stage fracturing was necessary to cover the entire reservoir thickness. Post-stimulation gas production was then predicted using the geometry and conductivity of the four propped fractures and the en‐ hanced permeability in the simulated volume due to shear slippage of natural fractures, us‐ ing a dual-porosity, dual-permeability reservoir simulator. For the purpose of comparison, a conventional gel fracturing treatment was also designed for the same well. It was found that two-stage gel fracturing was sufficient to cover the whole reservoir thickness. The gas production profile including these two propped fractures was also estimated using the reservoir simulator. The modeling comparison shows that the average gas flow rate after slickwater or low-vis‐ cosity treatment could be as much as three times greater than the rate after gel fracturing. It was therefore decided to conduct the slickwater treatment in the well. Due to some opera‐ tional complexities, the full stage 1 slickwater treatment could not be executed in the bottom zone and treatments in the other three zones have not been completed. However, the posttreatment production test results are very promising. The lessons learned in the planning, design, execution and production stages are expected to be a valuable guide for future treat‐ ments in the same field and elsewhere.

The challenges associated with tight gas developments include, the low initial production rates and the rapid production fall-off within the first years of production for any well. Tight gas developments require a multidisciplinary approach in which each element of a field development is addressed in order to develop the gas resources optimally. Each project will need to optimize the technologies and approaches used in order to successfully develop the tight gas resources. Experience from around the world may be relevant to some of these developments, but direct technology transfer from one field to another may not be relevant when the tight gas resources are on different continents with different geology and geological histories. This paper and presentation will address some of the experience gained in the Middle East and relevant North America experience during the appraisal phases of tight gas developments, focusing on how aspects of Geomechanical Engineering applied to stimulation design can be used to optimize initial production rates. In addition, it will address, as projects move from appraisal to the development stages, how Geomechanical engineering considerations may help in maintaining the production (reducing the production decline curve), through phased and structured development drilling campaigns.

An extensive suite of downhole geophysical logs was acquired through a 70 m thick section of basalt drilled by the Ocean Drilling Program (ODP) into 110 Ma oceanic crust 225 km SW of Hawaii. These data include standard sonic, electrical, and nuclear logs, as well as electrical and acoustic images of the wellbore, and enable a vertically continuous characterization of the physical properties of shallow, old oceanic crust. Fracture porosity and alteration increase with depth in this hole, and consid- ered together with results obtained elsewhere in both young and old (5 to 110 Ma) crust, suggest that physical proper- ties gradients in the uppermost few hundred meters of oceanic basement are controlled by crustal morphology and alteration and are ubiquitously variable. As this hole was drilled primarily for pilot experiments at the first site of the Ocean Seismic Network, evaluation of the log data demon- strates the importance of careful in-situ data collection in order to emplace a broadband monitoring device below the seafloor for long-term seismic measurements.

The French wireline re-entry expedition known as DIANAUT culminated in the successful completion of a series of downhole measurements in three Deep Sea Drilling Project (DSDP) holes in the north-central Atlantic Ocean. Among these measurements was a borehole televiewer (BHTV) log obtained in Hole 395A from bottom of casing at 112 meters below seafloor (mbsf) to a depth of 605 mbsf. In contrast with a BHTV survey previously conducted in this well during DSDP Leg 78B in 1981, televiewer data were not degraded by random cable oscillations due to ship heave and the quality of this log is excellent. These latest data were digitized and processed in terms of acoustic travel time and amplitude to compute hole size and shape, evaluate the structural integrity of the surrounding rock, and characterize intersecting fractures. The acoustic caliper and reflectivity logs correlate well with the lithologic column, particularly at the boundaries between major units which often are marked by breccias. Fractures in the lower part of the hole appear to be effectively sealed, in contrast with the open fractures identified in the upper sections. This supports a systematic pattern derived from complementary geophysical logs of increasing density, electrical resistivity, and elastic-wave velocity, and decreasing in situ permeability as a function of depth. Fractures intersecting the well exhibit a wide range of orientations marked by some clustering of dip azimuths approximately east-west. The presence of moderately dipping fractures striking subparallel to the ridge axis is consistent with both ridge-parallel topographic elongations observed in this area and with azimuthal seismic anisotropy reported elsewhere, suggesting that fractures such as those identified from the BHTV record contribute to these effects.

Deep, tight reservoirs face significant appraisal and development challenges. In particular, it can be difficult proving the presence and mobility of sufficient quantities of gas to make the reservoir economically viable. At the same time, drilling costs are extremely high. In this context, underbalanced drilling (UBD) provides a number of benefits: first, it enables the operator to proof (i.e., provide physical evidence for) the presence of producible quantities of gas (so-called “testing while drilling”) while the well is being drilled. Underbalanced drilling also can minimize formation damage and maximize the rate of penetration. This, combined with reduced use of expensive mud formulations, can result in significant savings of drilling and completion costs relative to conventional drilling. However, not all reservoirs are suitable for UBD as there is much greater risk of mechanical wellbore instabilities relative to wells drilled overbalanced. We present a new, realistic approach that enables to increase the accuracy of predictions and at the same time takes scale as well as time depenent effects into consideration. The results of this type of analysis can provide an invaluable help for tight gas reservoir exploration and production.

Borehole televiewer (BHTV) and 4-arm caliper (dipmeter) logs were obtained in the Toa Baja well (drilled to a depth of 2704 m into sediments of the North Coast Tertiary Basin, Puerto Rico) from 704 to 2676 m depth. The only observations suggesting that stress-induced wellbore failure (breakouts) had occurred were small intermittent features at a depth of approximately 2600 m with azimuths of 70° and 250° and the fact that, during drilling, wellbore stability became a problem near total depth. An increase in mud weight to 10 Lb/gal required to stabilize the deteriorating wellbore was accompanied by loss of drilling fluid into the formation, suggesting that hydraulic fracturing or the reopening of pre-existing near vertical fractures had occurred. A series of vertical fractures at a variety of azimuths (averaging N3l°W) was detected by the BHTV. The loss of circulation due to an increase in mud weight, combined with the absence of well-developed breakouts, enables us to estimate stress magnitudes near the well for reasonable values of rock strength: S1=Sv; S3=Shmin ≈ 0.5v; SHmax ≈ (0.55–0.63)Sv, and an associated incipient normal faulting stress regime. This stress regime is consistent with focal mechanisms determined for earthquakes with epicenters near the drillsite.

Reflectors imaged in a multichannel seismic line at Toa Baja, Puerto Rico, were studied by comparing the positions of reflection events with changes in rock properties determined through analysis of logs and cuttings. Reflectors appear to be associated primarily with changes in rock properties across facies or formation boundaries, and more rarely unconformities and faults. Faults that seal versus faults that leak can be recognized on the basis of gas Chromatograph data. Several laterally discontinuous reflectors characterized by modest amplitude anomalies seem to correlate in depth with minor shows of methane gas, measured by onsite gas chromatography. Gas was not recognizeable using geophysical logs indicating small quantities. The gas is apparently associated with rock types and rock properties which affect reflector amplitude rather than directly enhancing reflector amplitude.

This project uses advanced reservoir characterization tools, including the pulsed acoustic cased-hole logging tool, geologic three- dimensional (3-D) modeling software, and commercially available reservoir management software to identify sands with remaining high oil saturation following waterflood. Production from the identified high oil saturation sands will be stimulated by recompleting existing production and injection wells in these sands using conventional means as well as short radius and ultra-short radius laterals. Although these reservoirs have been waterflooded over 40 years, researchers have found areas of remaining oil saturation. Areas such as the top sand in the Upper Terminal Zone Fault Block V, the western fault slivers of Upper Terminal Zone Fault Block V, the bottom sands of the Tar Zone Fault Block V, and the eastern edge of Fault Block IV in both the Upper Terminal and Lower Terminal Zones all show significant remaining oil saturation. Each area of interest was uncovered emphasizing a different type of reservoir characterization technique or practice. This was not the original strategy but was necessitated by the different levels of progress in each of the project activities.

The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology. The identification of the sands with high remaining oil saturation will be accomplished by developing a deterministic three dimensional (3-D) geologic model and by using a state of the art reservoir management computer software. The wells identified by the geologic and reservoir engineering work as having the best potential will be logged with a pulsed acoustic cased-hole logging tool. The application of the logging tools will be optimized in the lab by developing a rock-log model. This rock- log model will allow us to convert shear wave velocity measured through casing into effective porosity and hydrocarbon saturation. The wells that are shown to have the best oil production potential will be recompleted. The recompletions will be optimized by evaluating short radius and ultra- short radius lateral recompletions as well as other techniques. Accomplishments for the past quarter are summarized for: reservoir characterization; reservoir engineering; deterministic 3-D geologic modeling; pulsedmore » acoustic logging; recompletions; and technology transfer.« less

The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology. The identification of the sands with high remaining oil saturation will be accomplished by developing a deterministic 3-D geologic model and by using a state of the art reservoir management computer software. The wells identified by the geologic and reservoir engineering work as having the best potential will be logged with a pulsed acoustic cased-hole logging tool. The application of the logging tools will be optimized in the lab by developing a rock-log model. The wells that are shown to have the best oil production potential will be recompleted. The recompletions will be optimized by evaluating short radius and ultra-short radius lateral recompletions. Technical progress is reported for the following tasks: Reservoir characterization; reservoir engineering; 3-D geologic modeling; pulsed acoustic logging; and technology transfer.

Cross-dipole measurements are obtained in a borehole. By estimating a direction of polarization of the fast shear mode at low and high frequencies and comparing the estimated distances, a cause of anisotropy is established. Formation stresses and directions may be estimated.

A method for simulating water-hammer waves in a borehole is used to estimate formation parameters such as porosity and permeability, and to design completion strings. The simulation method uses a model that has a plurality of layers, at least one of the layers includes radial layering.

Laboratory measurements reveal frame modulus dispersion and creeping behavior in room-dry samples of unconsolidated, quartzo-feldspathic Upper Miocene turbidites from the Wilmington Field, CA. A single standard linear solid model predicts both the dispersion and the creep response. Similar behavior is observed in Ottawa sand samples when mixed with wetted Montmorillonite. In this case the magnitude of dispersion and creep increase with increasing clay content. We suggest that the anelastic behavior of the Wilmington sands is due to the presence of micas and a small amount of clay. The transition frequency of 2×10−4Hz (i.e., between high and low frequency behavior) suggests that seismic, sonic, and ultrasonic measurements of rock moduli are quite similar in the absence of fluids. The static frame modulus should be used to model tectonic processes and long term production-related changes in oil-field environments.

The relationship between in-situ stress and fluid flow in fractured and faulted rock is examined by using data from detailed analyses of stress orientation and magnitude, fracture geometry, and precision temperature logs that indicate localized fluid flow. Data obtained from three boreholes that penetrate highly fractured and faulted crystalline rocks indicate that potentially active faults appear to be the most important hydraulic conduits in situ. The data indicate that the permeability of critically stressed faults is much higher than that of faults that are not optimally oriented for failure in the current stress field.

Earthquake focal-plane mechanisms and well-bore breakouts in the Long Valley caldera, California, indicate that the resurgent dome and caldera south moat are characterized by a northeast extensional stress field, consistent with geodetically determined extensional strain within the caldera. Similar data from the western caldera indicate that it is characterized by a markedly different, northwest-trending, extensional stress field. We hypothesize that this localized rotation of the stress field is possible because of near-lithostatic pore pressure at depth. Because an east-west extensional stress field appears to have existed in the western caldera at the time of emplacement of the Inyo volcanic deposits (500-1000 yr ago), the state of stress in the Long Valley caldera appears to be both spatially and temporally heterogeneous, most likely as a consequence of intracaldera processes related to magmatic resurgence.

The orientation, distribution and apparent aperture of natural fractures intersecting the Cajon Pass research well were determined through analysis of borehole televiewer (BHTV) data over the interval 1829 to 2115 meters. Large open fractures have shallow inclinations and tend to be aligned striking roughly N15°E. There is no apparent relationship between these fractures and the current stress state, as measured by the analysis of wellbore breakouts and hydraulic fracturing experiments in the Cajon Pass well and as observed in other studies in the region. Temperature anomalies due to fluid flow into the well detected during a long-term permeability experiment occur at several of these fractures. Compressional, shear and Stoneley guided wave velocities are within the expected range for crystalline rocks and elastic-wave anomalies are associated with the larger fractures. Stoneley wave coherence is reduced where the fractures are hydraulically conductive.

Sonic compressional and shear wave velocities were calculated from full waveforms recorded in the Cajon Pass drillhole from 250 to 1829 m depth. A complete suite of Schlumberger logs was also recorded over the same interval. Compressional velocities in the sediments (250-495 m) range from 3.3 to 4.0 km/s; shear velocities are unreliable. Shallow crystalline basement has low velocities (Vp < 4.8; Vs < 2.8 km/s) and resistivities due to minor alteration. Below 708 m Vp is 5.5 to 6.0 km/s and Vs is 3.2 to 3.5 km/s. Velocities are generally lower in more felsic rocks. In gneisses sonic waveforms are more distorted, semblance coherence is lower and physical properties are more variable. Mylonitized zones and fractured intervals have distinctly lower velocities but different aggregate log response. Lower velocities are found within a zone of fractures within the gneiss at about 840 m. Porosity increases only at one large fracture within the interval. In a mylonitized shear zone at 1440 m the velocity reduction and the porosity increase occur across the zone.

Cenozoic marine sediments were drilled and cored by the Deep Sea Drilling Project at Site 613 in the Baltimore Canyon Trough, and four‐channel sonic waveforms were recorded from 115 to 585 m below sea floor. Compressional wave velocities and spectra were calculated from the sonic waveforms. In situ porosity was estimated and compared to core measurements. As expected, velocity increased with depth as porosity decreased. However, the energy loss between near and far receivers increased and the peak crosspower frequency decreased with depth, suggesting that attenuation increases over the same interval. The large changes in energy and frequency cannot be explained solely by changes in the elastic propeties of the sediments. We model the observed compressional wave spectra using measured values of velocity and density. Reasonable fits to the observed spectra are obtained using either a constant Q (CO) or nonconstant Q model. For the CO model, O decreases from 100 to 20 over this depth interval. Diagenesis obs...

A study of the effects of macroscopic fractures on P and S wave velocities has been conducted in four wells drilled in granitic rock to depths between 0.6 and 1.2 km. The effect of macroscopic fractures is to decrease both Vp and Vs and increase Vp/Vs. In wells with a relatively low density of macroscopic fractures, the in situ velocity is similar to that of saturated core samples under confining pressure in the laboratory, and there is a clear correlation between zones with macroscopic fractures and anomalously low velocities. In wells with numerous macroscopic fractures, the in situ velocity is lower than that of intact samples under pressure, and there is a correlation between the rate at which in situ velocity increases with depth and the rate at which the velocity of laboratory samples increases with pressure. Differences in in situ P wave velocity between wells cannot be explained solely by differences in the degree of macroscopic fracturing, thus emphasizing the importance of composition and microcracks on velocity. In one highly fractured well the in situ P wave velocity is essentially the same for frequencies ranging from 10 Hz to 20 kHz; this suggests that the macrofractures affect velocity similarly over a broad frequency range. Chemical alteration of rock adjacent to macroscopic fractures appears to play an important role in reducing in situ velocities. Synthetic reflection seismograms generated from the velocity logs suggest that fracture zones are one possible source of deep-crustal reflectors observed on seismic reflection profiles.