Search

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.

Weak bedding planes create a unique mechanism for hydraulic fracture height containment, providing one possible explanation for unusual patterns of height growth in shale formations. This paper describes an investigation into how bedding planes modify the interactions between multiple, simultaneously propagating hydraulic fractures in a formation with weak horizontal interfaces with laterally varying properties. The investigation used a 3-D simulator that fully coupled geomechanics, fracture mechanics, and fluid behavior. Three equally spaced fractures were simulated along a horizontal trajectory. Fluid was injected simultaneously into all three locations, and partitioned according to maintain a specified total injection rate. Variations in perforation spacing, fluid viscosity and injection rate are modeled. The four designs investigated were: 1) 10-cp fluid, 20b-pm injection rate with 30-m cluster spacing. 2) 100-cp fluid and 20-bpm fluid injection rate with 30-m cluster spacing. 3) 10-cp fluid and 40-bpm injection rate with 30-m cluster spacing. 4) 10-cp fluid, 20-bpm and 45-m cluster spacing. Results showed how these changes affected fracture area and shape. The propped surface area for each scenario was also estimated. The results suggested that the presence of laterally varying weak interfaces can significantly affect fracture interference.

A field-specific geomechanical model serves as a platform for greatly reducing costs and increasing production over the life of a field. The information contained in a geomechanical model makes it possible to reduce drilling costs and production losses through fieldwide well planning that can optimize production and minimize risk. A significant value of the geomechanical model is its application to the efficient exploitation of fractured reservoirs. The essential contribution of wellbore image technologies to this exploration and production challenge is illustrated through a case study of a compartmentalized fractured gas reservoir located in Hokkaido, Japan. A growing body of evidence reveals that, in many fractured reservoirs, the most productive fractures are those that are optimally aligned in the current stress field to fail in shear. Thus, it is necessary to obtain knowledge of both the stress magnitudes and orientations and the distribution of natural fractures to determine the optimal orientations for wells to maximize their productivity. The best well intersects the maximum number of stress sensitive fractures. Applying geomechanics and the reservoir fracture distributions to model shear-enhanced permeability as the mechanism for reservoir production appears to be a promising improvement to existing reservoir flow models. Using quantitative risk assessment and realistic uncertainties in the critical parameters, it is possible to estimate the uncertainty in predictions of optimal well trajectories and of stimulation pressures to enhance natural fractures. The results indicate that the critical parameters are not always those with the most uncertainty, and that the most effective way to reduce prediction uncertainties is to calibrate against the productivity of a preexisting 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.

A comprehensive geomechanical approach to wellbore stability requires knowledge of rock strength, pore pressure and the magnitude and orientation of the three principal stresses. These parameters are often uncertain, making confidence in deterministic predictions of the risks associated with instabilities during drilling and production difficult to assess. This paper demonstrates the use of Quantitative Risk Assessment (QRA) to formally account for the uncertainty in each input parameter to assess the probability of achieving a desired degree of wellbore stability at a given mud weight. We also utilize QRA to assess how the uncertainty in each parameter affects the mud weight calculated to maintain stability. In one case study, we illustrate how this approach allows us to compute optimal mud weight windows and casing set points at a deep-water site. In another case study, we demonstrate how to assess the feasibility of underbalanced drilling and open-hole completion of horizontal wells utilizing a comprehensive stability analysis that includes application of QRA.

SummaryA study of in-situ stress, rock strength, and wellbore stability was initiated in the Hemlock sands of the McArthur River field, Cook Inlet, Alaska, to evaluate the potential of leaving the near-wellbore portions of multilaterals uncased. A northwest/southeast direction of maximum compression and a strike-slip faulting regime were predicted from analyses of leakoff test data and observations of failure (breakouts) in adjacent wells. Caliper, well-log, and core data indicated that cementation, and hence rock strength, is highly variable within the reservoir. Thus, it was decided to evaluate the stability of the lateral sections (i.e., the likelihood of wellbore failure during production) as a function of both stratigraphic position and well orientation. Laboratory rock-strength measurements were carried out on cores selected from target intervals in adjacent wells to provide sufficient precision to quantify the results. The results indicated that, while some reservoir intervals have high enough strengths to be left uncased when drilled in the most stable direction, these intervals are too thin to provide sufficient support at the point where the laterals leave the parent well. This justified the decision to case back the laterals to the parent well despite the cost.

Gassmann’s (1951) equations relate the elastic bulk (Ksat) and shear (Gsat) moduli of a fully saturated rock to the elastic bulk and shear moduli of the dry‐rock frame (Kdryand Gdry, respectively), porosity ϕ, and the bulk moduli of the mineral phase [Formula: see text] and pore fluid [Formula: see text].

Intelligibility is a design principle for context-aware systems which focuses on providing information about context acquisition and interpretation to its users. In this paper we present existing approaches to provide intelligibility and identify a common shortcoming. Explanations starting on the context level are insufficient to help users in finding and understanding why their system is not working. Debuggability for context-aware systems is introduced as a means to assist users in debugging the cause of a failure. To achieve this we adapt an information exchange approach from explanatory debugging. Furthermore we discuss open problems of debuggability and provide a possible solution.

Controlling a dynamic and distributed device ensemble is challenging. Such ensemble should support their users pro-actively, by taking useful actions automatically. Here, we propose an approach in which methods of deployed objects are annotated with preconditions and effects. From those annotations, we construct planning operators that are used in a distributed planning system. The resulting system is able to control a real laboratory infrastructure without any central control component such that goal-directed behavior emerges from the interplay of all deployed devices.

Fractures and faults provide permeable pathways for fluids throughout the crust, from aquifers in the shallow subsurface to crustal depths where they can control production in geothermal fields and hydrocarbon reservoirs. Fracture‐enhanced permeability depends on fracture density, connectivity and, most importantly, the hydraulic conductivity of the different fracture and fault planes.

In the Eurasian part of the World Stress Map almost the whole region east of the Tornquist-Teisseyre line is terra incognita. The closure of this information gap is of fundamental importance to the understanding of the geodynamics of the Eurasian continent. A detailed analysis of stress-induced wellbore breakouts has been performed over a 4.1-km-long depth interval in the Vorotilov drillhole (VGS). The borehole is located in the central part of the Russian platform, right in the center of the Vorotilov meteorite impact crater 60 km to the NNE of the city of Nizni Novgorod. An ultrasonic borehole televiewer (BHTV) was used to obtain high-resolution acoustical images from the borehole wall. With an interactive system for analyzing BHTV data the azimuth and shape of borehole breakouts occurring in the depth range of 1.3–4.8 km were analyzed. A statistical analysis of the resulting orientation profile of the breakout azimuths yields an overall direction of the maximum horizontal principal stress S H of N 137°E ± 15°. Variations of breakout orientation with depth ranging from a few degrees up to more than 90° are seen on various depth scales. The observed stress direction of N 137°E agrees very well with the average S H orientation of N 145°E in Central Europe. If this measurement is taken as representative for the Russian platform, the stress field in Russia is only slightly rotated in comparison to Central Europe. This can possibly be interpreted as indicative for the stress field to be governed by broad scale tectonic forces, such as a strong contribution from the forces exerted by the collision zone in the Alpine-Himalayan belt and by the Mid-Atlantic ridge.

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.

Recent seismic experiments have revealed that a shallow, low velocity zone is a common feature within the uppermost few hundred meters of very young (less than 100 kyr) oceanic crust at ‘fast spreading’ ridges. The shape of this zone suggests that the low velocities are related to the constructional morphology of the extrusive (layer 2A) portion of the crust. With this in mind, we use simple analytical techniques to study the effects of characteristic morphologic elements of the extrusive basalts on their elastic properties. We find that high compliance of the contacts between pillows and pillow fragments can account for all of the observed velocity anomaly. Voids between pillows are, by comparison to their effects on porosity, considerably less important. Radial (cooling) cracks and voids within the pillows themselves will affect the velocities in direct proportion to their effect on the individual pillows. The relatively rapid increase in velocity with age in these very young extrusives can be explained by welding of pillow contacts and stiffening of the individual pillows by infilling of radial fractures, both of which may take place without a large reduction in porosity. If voids between pillows are filled initially by sediments, the cementation of these materials can also cause large increases in velocity without a large addition of mass. Because of the importance of such subtle variations in morphology, there can be no one-to-one relationship between seismic velocities and porosities within the extrusive layer of the oceanic crust. Therefore independent measures of crustal porosity must be found (for example, using sea floor gravity surveys).

Exploitation of unconventional shale gas reservoirs depends on successful hydraulic fracturing and horizontal drilling. Mineralogy, organic matter content, acoustic anisotropy, and in-situ stress all play an important role for well completion design. As part of a comprehensive site study of the Upper Devonian Huron shale, borehole acoustic and mineralogy logging data, in addition to conventional logs, were acquired in a vertical well prior to hydraulic fracturing and microseismic monitoring of a series of laterals drilled from the same location. The acoustic data was processed for compressional wave, cross-dipole shear, Stoneley-derived horizontal shear, radial velocity variations, and borehole Stoneley reflectivity indicators. The cross-dipole anisotropy and the near-well radial slowness variations provided information about intrinsic anisotropy and stress sensitivity to determine the source of dipole-mode anisotropy. Significant transverse acoustic anisotropy was detected and used to obtain vertical and horizontal dynamic elastic properties. The mineralogy and petrophysical analysis were used to generate a micromechanical constitutive model to reproduce numerically the laboratory stress-strain behavior of the rock, from which quasi-static mechanical properties were determined. These were calibrated against triaxial tests on core samples from an offset well, and the vertical and horizontal static elastic rock properties were used to estimate the vertical variation of the horizontal stress. The resulting stress profile, along with accurate mineralogy and petrophysical analysis, provides important information to select the best vertical locations of lateral wells and to identify natural fracture barriers.

The "Shale Engineering" approach and modeling addresses production forecasting in shale and tight formations. This new reservoir simulation methodology relies on modeling the propagation of the stimulated rock volume from the near-well vicinity to deep into the formation. Simulation models are built for individual fracturing stages and validated by matching treatment pressures and rates while conforming to geomechanical and microseismic observations. Stage models are then combined into a larger well model where individual stage contribution and early production performance are matched. This approach was applied on a project that was developed by EQT in an Upper Devonian shale formation in West Virginia. Data available for this project included fit-for-purpose formation evaluation description, production logs and downhole microseismic data with advanced processing and interpretation. The results provided a good match to early well performance, despite the complexity of having to match a combination of shales and partially depleted tight sandstones that had been stimulated by foam fracturing with proppant. This approach can be used not only to predict production, but also as a practical platform for field development design and optimization. Furthermore, the matched results validated the shear stimulation model developed by the authors for this type of application. The approach makes it possible to exploit microseismic observations in a more realistic way in order to describe the stimulated rock volume (SRV), and it explains early-life production logs that indicate uneven fracturing stage contribution. The model also can relate stimulation effectiveness to pre-existing formation rock and fluid properties, and thus can be used as a guide to identify optimal formation targets. The "Shale Engineering" approach hinges on the premise that when unconventional "tight rocks" containing hydrocarbons are modified by hydraulic fracture stimulation, the process converts them into "reservoir rocks". In addition, interpretation of the newly created "artificial reservoirs" is accomplished through multi-displinary expertise that is focused on providing a rate performance and predictive model to aid in reservoir development. Because unconventional resource/reservoir formations are unique and subject to a wide range of conditions, they require a production predictive method more suitable for this task than the commonly used "Type Curves". The advantage of the "Shale Engineering" approach is that it allows validation with parameters that can be available at an early stage of the well life, which in turn are useful to constrain model solutions. It also offers the means to include geomechanics in a practical workflow that allows systematic workflow allows for step-by-step validation of the model. The suggested simulation process uses commerical software and it can be applied to either simple or complex cases.

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.

A comprehensive site study carried out in an Upper Devonian shale gas reservoir at a site in southern West Virginia provided data to test a geomechanical model for stimulation of the Huron formation. Using a model in which natural fractures provide the primary conduits for production and are the major target for stimulation, and in which stimulation triggers shear slip on those pre-existing fractures, we were able to predict the shape of the reservoir volume stimulated by injection of high-quality foam and to match injection flow rates and pressures using a dual porosity dual permeability finite-difference flow simulator with anisotropic, pressure-sensitive reservoir properties. The resulting calibrated model matched both the relative contribution of the individual stages measured by production logging and the early-life well production. This suggests that similar models may in the future provide earlier and better production predictions, guidance for completion and stimulation design, and recommendations to minimize production decline and maximize well value.

Today’s advanced borehole acoustic analysis not only enhances the rock physic characteristics of shale gas plays but it also provides new insights in geomechanics applications and fracture identification. Current borehole acoustic tools can detect the azimuthal and transverse shear wave intrinsic rock anisotropy. They also help identify stress-sensitive formations and help in the evaluation of natural fractures, those that intersect the borehole as well as those that do not.

Hydraulic fracturing stress measurements have been conducted in crystalline rock at two locations within the southeastern United States at depths from 50 meters to more than one kilometer. Stress orientations are similar to those obtained from other local and regional stress indicators and are consistent with a ridge-push source of intraplate stress. High horizontal stress magnitudes (with respect to the vertical stress) are found only in the near-surface. Thus, although relatively shallow stress orientation measurements appear to be reliable indicators of the stress orientation at greater depth, stress magnitudes cannot be extrapolated quantitatively beyond the depth range of the measurements.

Ultrasonic compressional and shear‐wave velocities of isotropic sands are shown to be dependent on their mineralogy, their porosity, their fluid content, and their state of consolidation, under fixed temperature and pressure conditions. This leads to a distinction between two broad classes of sands: those that are well consolidated, and those that are loosely consolidated. Changes in elastic velocities reflect changes in the ratio of bulk and shear moduli to density in response to lithologic variations. We decouple the two effects by examining changes in elastic moduli with respect to changes in lithology, and we observe three main points: (1) For consolidated sandstones, the effects of mineralogy and porosity can be approximated both empirically and theoretically by a modified isostrain theory: the dry bulk and shear moduli of the rock aggregate follow a “mixing law,” being linear combinations of the respective moduli of the individual constituents. The dry elastic moduli of families of clean sands and shaley sands are linear functions of porosity, with decreasing y‐axis intercepts as their clay‐to‐sand ratio increases. (2) Loosely consolidated sands and sandy shales appear to follow a behavior closer to that of the isostress theory for suspensions: the reciprocals of the bulk and shear moduli of the rock aggregate are linear combinations of the reciprocal moduli of their individual constituents. In general, the elastic moduli of poorly lithified sands are less sensitive to changes in mineralogy and porosity than those of consolidated sandstones. (3) For high permeability sands like the loosely consolidated sands of Troll, the Biot‐Gassman theory is a good approximation to the effects of fluids on seismic velocities. With our understanding of elastic moduli, we then show that dry ratios [Formula: see text] increase with porosity and clay content.

We have developed a new analytical model for underbalanced drilling (UBD) that takes into account that rocks have scale dependent strengths, that the full stress concentration is not developed at a given depth in a well until sometime after the drill bit has passed, and that fluid flow into the advancing wellbore leads to a zone of locally lower pore pressure surrounding the well that extends beneath the drill bit. The model predicts regions within which compressive shear failure will occur and also provides predictions of where spalling (tensile failure) is a possibility. The results provide a more realistic and less conservative prediction of wellbore risk than models developed to study the stability of overbalanced wells. This new model can be applied to predict whether underbalanced operations are possible in a given well, and also the severity of wellbore instability as a function of underbalance. In addition, the model allows constraints to be placed on the in situ stress field (magnitudes and orientations) based on observations of wellbore failure in wells which have been drilled underbalanced. Wells designed utilizing model predictions were drilled without incident, and the model also provided reasonable predictions of the state of stress.

There is worldwide interest in the development of shale plays: North America has attracted noteworthy investments, while other continents are ready to follow that example. Besides the increasing commercial significance of shale plays, traditional volumetric and material balance approaches that are used for petroleum asset evaluation fail to address the special attributes of such formations, or they cannot rely on measurable and practical input. The current practice is to statistically analyze historical records in developed areas and to apply the derived type curves in new areas by assuming performance similarity. Provided that there is a sufficient statistical record base, the assumption of similarity is challenged by the multitude of parameters influencing performance. These tend to differ, introducing considerable uncertainties into predictions. As the advanced drilling and fracture stimulation techniques were introduced in the last decade, historical records support only the early production history, while late performance is extrapolated without many reference points to match. This paper investigates the applicability of traditional and non-traditional empirical, analytical and numerical methods that are used to predict shale well performance. The goal is to rationalize the link between natural/stimulated rock description with oil and gas recovery mechanisms in a way that is practical at various scales of resolution and covers early and late times. The authors have investigated the application of performance analysis techniques that are fit for macroscopic view and numerical methods that describe multiple mechanisms at a much higher level of resolution. Special features such as flow through fracture networks, gas desorption and geomechanical effects are incorporated in numerical simulation in a way that relates to the measurable petrophysical and geophysical input. Although the application of such macro- and micro-analysis has been examined within only a few case studies, it is suggested that future work would test and improve the application of these shale engineering principals. In retrospect, this study offers an understanding of mechanisms and limitations that can be used for optimization, or for the scaling-up results from a certain area to other areas that differ in natural attributes and may also adopt different design and operational practices. The simulation exercise reported in this paper represents an idealized situation and it should not be inferred that this can be used to indicate recovery from any specific shale reservoir or well, which would require additional study and appropriate incorporation of practical data that were not available to the authors in the public domain.

A field-specific geomechanical model serves as a platform for dramatically reducing costs and increasing production over the life of a field. The information contained in a geomechanical model makes it possible to assess exploration risk associated with fault-seal breach caused by fault slip. Using model-specific stress, pore pressure, and rock properties information, drilling engineers can provide recommendations for efficient well design and placement to reduce adverse events such as stuck pipe and lost circulation. A geomechanical model also makes it possible to design completions to avoid or manage solids production and to extend the productive life of wells. In addition, the effects of reservoir depletion and injection can be predicted to enable optimal exploitation that avoids excessive reservoir damage, casing collapse, and hazards related to leakage of produced or injected fluids. The essential contribution of wellbore image technologies to these exploration and production challenges is illustrated through recent case studies that apply wellbore imaging technologies to the detection, access, and recovery of hydrocarbons. Future reservoir development and management practice will demand an increased use of imaging techniques to ensure successful production in risky drilling environments, reduce the costs associated with drilling, and increase the economic lifetime of mature reservoirs.

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.

Water hammer effects resulting from the shutting in of water injection wells are an often ignored issue in petroleum production operations but they have considerable impact on injection well performance and longevity. Mismanaged, they can result in substantial and perhaps irreparable damage. This paper presents a study on the creation and propagation of water hammer due to rapid shut-in of water injectors.Water hammer1-4 or pressure surge, is a pressure transient phenomenon which has long been known to occur as a result of a sudden change in fluid flow velocity. In water injectors, rapid shut-in creates a water hammer. Over time, injectors that undergo repeated rapid shut-ins often have significantly reduced injectivity and show evidence of sanding and even failure of the down-hole completion5. It is therefore critical to understand the nature of water hammer including the magnitude, frequency, and energy dissipation.To study the water hammer in water injectors, a field trial was conducted to record pressure pulses generated from rapid shut-ins, at different well depths, in a soft formation, cased and perforated (C&P) water injector. Modeling work was conducted to understand the data.The results of the field trial and model work demonstrated that:The magnitude of the first pressure pulse due to abrupt shut-in can be estimated by using the equation: Δp = V×ρ×c, where V is the flow velocity, ρ is the fluid density, and c is the speed of propagation of a pressure signal along the well. High rate sampling (up to 100 samples/second) is required to capture subtle details of the water hammer signal. Water hammer can be modeled as a low-frequency pressure wave similar to the higher frequency Stoneley waves produced during VSP and by acoustic logging tools. Models of water hammer propagation in a synthetic analog of the test well reproduced most of the details of the signals recorded during the tests.

Whilst the step-out lengths of proposed ERD wells are becoming more and more challenging, wellbore stability assurance technologies - both in the pre-planning and execution phases - are developing at an equal pace. In this paper we describe several new developments in theoretical understanding and predictive capability of rock failure surrounding wells drilled at high-angle to bedding that are required to solve the problems encountered in these challenging environments. Rig-site processes for the integration of this new understanding with real-time diagnostic measurement and monitoring provide the means to deliver borehole stability assurance for ERD wells drilled in the most challenging environments.

Understanding borehole stability has become increasingly important in recent years to facilitate design of costly horizontal wells. This paper presents a case study, in which we evaluated the stability of a horizontal well in a major California oil field by first determining rock strength and tectonic stress and then drilling the well to verify the results of the predictions. Given the opportunity to drill numerous horizontal and possibly multilateral wells, it was important to fully evaluate the possibility of a successful open hole completion. An 800-foot horizontal well was planned to be drilled within a poorly consolidated and highly porous Pliocene reservoir that is slightly over pressured.The analysis revealed that one horizontal principal stress is greater and one is lower than the overburden. Maximum horizontal compression is oriented N60°E. Borehole stability of the horizontal well is predominantly controlled by the extremely weak reservoir rock (uniaxial compressive strength is only 1,175 psi). An open hole completion was predicted to collapse without supporting slotted liner or casing. Even for a cased well, perforations placed at their most stable orientation were predicted to produce considerable amounts of sand. Only 200 feet of open horizontal hole was tested to validate the prediction. The open hole produced briefly and then collapsed. The horizontal well was subsequently completed in 800 feet of interval using a 60 mesh slotted liner and has produced 15,657 bbls of oil, 291 bbls of water, and 41,181 Mcf of gas through 12/31/99 with no sand problems.

Drilling problems frequently result from severe mechanical failure of the wellbore wall and thus depend on the interplay between the magnitude and orientation of in situ stresses, rock strength, mud weight, and the orientation of the wellbore. Utilizing a new suite of software tools developed to study wellbore stability in a wide variety of geologic environments, we can accurately predict optimally-stable wellbore trajectories from knowledge of the stress tensor. The analysis is a two step process – first, we determine stress from observations of failure in existing wells. We can then apply this knowledge to predict the stability of proposed wells both while drilling and later during production. We illustrate this type of approach using three case studies. First, we combine observations of failure in a vertical well with rock strength measurements to demonstrate the feasibility of horizontal drilling in poorly consolidated reservoir sands. Next, we analyze the stability during production of a series of multilaterals drilled from a single inclined parent well. Finally, we show that wellbore stability can be controlled by the orientation of a well with respect to bedding, and illustrate a method to optimize the trajectory of wells to account for this effect.

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

Theoretical relationships, confirmed by laboratory and field data, suggest that hydrocarbon-bearing rocks in situ can be differentiated from rocks containing brines using sonic velocity measurements. A project to test this technique has been undertaken in the Wilmington Field, California. Models, using values of fluid and formation properties typical of the Miocene-age turbidites within the target interval, confirm that it should be possible to differentiate between hydrocarbon and non-hydrocarbon bearing sands in this field using compressional and shear wave sonic velocity logs. To date six wells (ranging in age up to 50 years) have been logged through casing with multipole sonic logging sondes. There is remarkable agreement between compressional velocities determined using two different tools and analysis methods. Also, velocities measured in open hole agree with those measured after casing was installed in the most recently drilled well. Although compressional velocities have been determined in all but one case, shear-wave velocities have been obtained only in the most recently drilled wells and only where differences between dipole mode and tube wave velocities are sufficiently large. Porosity can be determined from shear-wave velocity using models for unconsolidated sands presented by Dvorkin and Nur (in press). Predictions of oil saturation are in qualitative agreement with models and with open-hole determinations.

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 number of key questions need to be addressed before the relationship between stress and fluid flow in the Earths crust can be understood. First, how is fluid flow related to the current stress field in highly fractured crystalline rock? Second, is enhanced permeability and permeability anisotropy principally the result of flow along joints (Mode I failure) or shear faults (Mode II failure) or both? Is it possible that answer is neither - that in highly fractured crystalline rock, flow is dominated by the orientation of faults and fractures introduced into the rock mass during its long geologic history and the orientation of these structures bears no strong relation to the current stress field? It is well known that relatively few fractures in fractured rock serve to conduct fluids through the rock. The use of fracture geometry to predict hydrologic flow in the crust is therefore severely limited by the lack of knowledge of which fractures measured in a given survey actually provide conduits for fluid flow. This study examines the relationship between in situ stress and fluid flow using data from detailed analyses of wellbore breakouts and fracture geometry in conjunction with precision temperature logs.

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.

In the following case study, cross-well seismic tomography was used to image both structural and stratigraphic features in Gulf Coast Miocene sediments. A piezoelectric downhole source was used to produce seismic waves which were recorded by hydrophones between wells 250 apart. Traveltime tomography was then applied to a set of over 5000 picks. In addition to the targeted fault delineation, the tomography successfully imaged a number of porous sandstone layers previously identified from type logs for the Miocene. Two different methods of traveltime picking and tomographic inversion were used. The two resulting velocity tomograms show similar velocity variations that lead to a consistent geological interpretation. Borehole gravity meter (BHGM) data, obtained in both wells following the tomographic survey, were used to associate densityvariations with the velocity features imaged by the tomography. The lD BHGM-derived low density zones were found to coincide with the 2D seismically imaged low velocity zones, thus supporting the identification of porous sandstone layers.