Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Europe
Abstract: This study focuses on productivity of low-permeability shallow biogenic gas reservoirs of the Upper Cretaceous Milk River Formation. This formation is one of the major producing intervals of biogenic gas in southeastern Alberta and southwestern Saskatchewan, Canada. We show in situ stress measurements for shallow depths in this region that indicate a cross-over between the vertical stress and minimum horizontal stress at about 370 m depth; shallower than 370 m, the vertical stress is the minimum principal stress. In situ stresses have a profound effect on the orientation of induced hydraulic fractures and stress information can be used to predict whether induced hydraulic fractures are vertical or horizontal. This information is helpful in designing an optimum completion strategy for multi-layered compartmentalized shallow reservoirs and on choosing the best assets to develop. A vertical in situ stress map is constructed for the top of the Milk River Formation to examine possible relationships between the overburden stress and the productivity of the Milk River Formation reservoirs. We demonstrate that a strong relationship exists between the in situ stress and productivity: better well performance is observed in the regions where the vertical stress is lowest. Hence, vertical in situ stress mapping is helpful to delineate areas of best productivity "sweet spots".
- North America > Canada > Saskatchewan (1.00)
- North America > Canada > Alberta (1.00)
- Europe (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > South Dakota > Williston Basin (0.99)
- North America > United States > North Dakota > Williston Basin (0.99)
- (17 more...)
ABSTRACT: Decreasing development costs and risks involves optimizing field development plans, refining drilling programs and making good predictions of production rate. In achieving these goals, it is important to investigate the geomechanical behavior of the reservoir. All data and information recorded during exploration, drilling and production are used for estimating the mechanical properties and earth stresses in the stratigraphic section by constructing a Mechanical Earth Model (MEM). We focus here on building a 1D MEM for one well in a reservoir in southwest Iran, and then we apply the model to well design and construction for field development through generation of a drilling mud weight strategy based on the MEM. General lack of calibration data, especially for stress measurements, means it is necessary to use different methods to determine the rock properties and the stress state. Since there is limited knowledge about the stress state, different stress states are discussed and possible principle stresses are determined based on the comparisons of drilling reports, image logs, and wellbore stability conditions. These considerations and comparisons suggest that the ratio of horizontal to vertical stresses should be less than 0.7, which means that the stress regime of the study area is one of normal faulting. 1. INTRODUCTION Understanding and managing risks associated with rock deformation (borehole instability, changes in productivity, hydraulic fracture treatment design…) through analysis provides engineers with both technical and economical means to effectively identify, predict, and prevent costly events and to optimally manage drilling and operation of oil wellbores [1]. A production development plays a prominent role in all phases of exploration, drilling and production. In the oil and gas industry, well-constrained predictions undoubtedly increase economic benefits, whereas unmanaged uncertainty leads to losses during drilling and completion activities, and even reduced production capacity during the exploitation phase [2].
- North America > United States (0.93)
- Asia > Middle East > Iran (0.72)
- South America > Colombia (0.93)
- Europe > United Kingdom > North Sea (0.93)
- Europe > Norway > North Sea (0.93)
- (2 more...)
ABSTRACT: Fracture system characteristics in naturally fractured carbonate reservoirs seem central to any development plan. In this article, a combination of outcrop studies, core studies, seismic, and borehole image logs were used to characterize natural fractures in a naturally fractured carbonate heavy oil field in Iran. A field study of fractures at the surface and in the sub-surface was conducted and regional tectonic fracture systems characterized. Three general orientations of mainly vertical and sub-vertical fractures were identified and characterized over the crestal area. Two main fracture sets, one shear conjugated and the other clearly a tensile fracture set, were identified. The frequent shear fractures resulted from compressional tectonics forces. This type of fracture is normally tight and impermeable but in his field they have largely been opened as the stress regime changed to a tensile tectonic regime by bending, accompanied by uplifting or drag folding, thus creating high-permeability fractures. Results obtained from this study can be implemented in optimizing well placement, reservoir simulation, hydraulic fracture design, and evaluation of the studied heavy oil field for appropriate production technology. 1 BACKGROUND Saidi [1] defined a Naturally Fractured Reservoir (NFR) as a reservoir that contains fractures (planar discontinuities) created by natural processes (e.g., tectonic forces) distributed as a consistent connected network throughout the reservoir. NFR’s are usually thought to comprise of an interconnected fracture system that provides the main flow paths (high permeability and low storage volume) and the reservoir rock or matrix that act as the main source of the hydrocarbons ( low permeability and high storage volume). Thus, it is the matrix system that contains most of the oil but the production of oil into the wells in through the high permeability fracture system, implying that it is the matrix-fracture interaction that mainly control the fluid flow.
- North America (0.93)
- Asia > Middle East > Iran (0.89)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.94)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > California > Sacramento Basin > 3 Formation (0.99)
- Europe > Norway > Norwegian Sea > Møre Basin (0.99)
- Asia > Middle East > Iraq > Zagros Basin (0.99)
- (4 more...)
ABSTRACT Naturally fractured reservoirs are considered extremely challenging in terms of accurate recovery prediction because of their complexity and heterogeneity. Conventional simulators only consider pore compressibility as a geomechanical parameter for simulation and assume permeability and porosity as static or pressure-dependent variables. These assumptions are insufficient from a physics point of view because porosity and permeability are functions of effective stress and temperature as well as pressure. Thus, parameter impact on both reservoir characterization and simulation processes should be considered via a thermohydro- mechanically (THM) coupled approach for a more precise simulation. In this paper, a review of THM coupling methods in the petroleum industry is presented, with emphasis on naturally fractured reservoirs. The governing equations for a thermohydro- mechanical coupling are introduced in a fully coupled formulation, and applications of this approach are discussed. Introduction In the last two decades, there has been a strong emphasis on the importance of geomechanics in petroleum engineering. In reservoir management, geomechanics plays a role as a multidisciplinary aspect among the various other engineering specialities (geology, fluid flow, and thermodynamics). In fact, the term "geomechanics" is often applied very broadly to describe a wide range of reservoir phenomena. The origins of formal geomechanics are based on the concept of effective stress and consolidation for incompressible solid grains formulated by Terzaghi in 1936. Based on the concept of Terzaghi's effective stress, Biot investigated the coupling between stress and pore pressure in a porous medium and developed a generalized three-dimensional theory of consolidation with the basic principles of continuum mechanics [1]. He also to some degree extended poroelastic theory to anisotropic and nonlinear materials. Biot's theory and published applications are oriented more toward rock mechanics than fluid flow. Because of this, Biot's theory is less compatible with the conventional fluid-flow models (without geomechanics consideration) in terms of concept understanding, physical interpretation of parameters (e.g., rock compressibilities), and computer code development [2]. Skempton (1960) derived a relationship between the total stress and fluid pore pressure under undrained initial loading through the so-called Skempton pore pressure parameters A and B. Geerstma (1957) gave a better insight of the relationship among pressure, stress and volume, clarifying concept of compressibility in a porous medium. He also explained calculation of reservoir porosity using volumetric strain. Van der Knaap (1959) extended Geertsma's work to nonlinear but elastic geomaterials, such as dense but uncemented sands. Nur and Byerlee (1971) proved that the effective stress law proposed by Biot is more general and physically sensible than that proposed by Terzaghi. In other developments that are relevant to coupled flow-stress problems, Ghaboussi and Wilson (1973) introduced fluid compressibility into classic soil mechanics consolidation theory. Rice and Cleary (1976) showed how to solve poroelastic problems by assuming pore pressure and stress as primary variables instead of displacements as employed by Biot.
- Europe (0.95)
- North America > United States > Illinois (0.28)
- North America > Canada > Ontario (0.28)
- North America > United States > California > Los Angeles Basin > Wilmington Field (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- (2 more...)
Predicting Inter-well Rock Mechanics Parameters Using Geophysical Logs And 3-D Seismic Data
Zhang, Y.G. (Daqing Oilfield Co. Ltd) | Han, H.X. (University of Waterloo) | Dusseault, M.B. (University of Waterloo) | Wang, X.J. (Daqing Oilfield Co. Ltd.) | Zhang, Z.X. (Daqing Oilfield Co. Ltd) | Fan, K.M. (Daqing Oilfield Co. Ltd) | Yu, Y.M. (Daqing Oilfield Co. Ltd)
ABSTRACT ABSTRACT: We introduce an inter-well rock mechanics parameters prediction method using a combination of geophysical well logging data and 3-D seismic data. The method has been used to estimate Poisson¡¯s ratio (¦Í), Young''s modulus (E), fracture closure pressure (PCL), and fracture breakdown pressure (PBD) during fracture treatments, for any reservoir location in the rock volume analyzed. The statistical approach is based first on explicit correlations between static core analysis of rock mechanics parameters and dynamic multi-pole-array sonic logging. By further multiple linear regression analysis, these parameters can in turn be correlated to common well logging curves. Then, inter-well rock mechanics parameters are estimated through the use of the 3-D seismic database, constrained statistically using the logging data from individual wells. As a result, a 3-D rock mechanics properties model is developed for the volume covered. Relevant rock mechanics parameters at any point in the volume can be estimated from the model, allowing hydraulic fracture engineering design to be undertaken before an infill well is drilled. 1 INTRODUCTION There has been growing interest in determining insitu dynamic rock mechanical (lithomecanical) parameters in the oil and natural gas E&P industries. Various methods are available for measuring rock mechanics parameters. Mechanical and petrophysical properties are usually obtained from core sample tests using standardized laboratory procedures. This method is limited by the availability of core and by the cost of testing. Although interactive multi- pole-array sonic logging is an important tool for analyzing lithomechanical parameters, logging cost is too high for such tools to be used extensively. A mechanical earth model is one of the key tools for rock mechanical properties characterization as well as for provision of data to implement fully coupled reservoir geomechanics simulation.
- North America (0.68)
- Asia > China > Heilongjiang Province (0.49)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 103 > Block 25/8 > Jotun Field > Ty Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 103 > Block 25/8 > Jotun Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 103 > Block 25/8 > Jotun Field > Smith Bank Formation (0.99)
- (27 more...)
- Well Drilling > Wellbore Design > Rock properties (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
How Much Oil You Can Get From CHOPS
Han, G. (Hess Corporation) | Bruno, M. (Terralog Technology Inc.) | Dusseault, M.B. (University of Waterloo)
Abstract Cold Heavy Oil Production with Sand (CHOPS) has been applied with very good success to enhance heavy oil production in Canada, China, Venezuela and Kazakhstan. Based on existing laboratory and field information and case histories, the most important physical processes enhancing cold production have been reviewed, summarized and quantified. Several sanding models are developed, including a new porosity cap model for failure propagation, as well as a semi-analytical elastoplastic stress model coupled with an unsteady pressure model for foamy oils. The mechanisms for oil rate enhancement by CHOPS, such as porosity and permeability enhancement that arise from sand removal, propagation of the elastoplastic (remolded) zone, increase of oil velocity relative to the matrix and the effects of foamy oil behaviour, are quantitatively described and compared. The proposed model can be applied to predict how much additional oil one might expect for a given amount of produced sand. It might also serve as a tool for optimizing cold heavy oil production while nevertheless keeping the sand flux at a low level, which could reduce operating expenses such as limiting sand disposal costs. Introduction There may be more than 0.95 × 10 m of heavy oil in the World, compared to 0.28 – 0.37 × 10 m of conventional oil, of which over 40% has already been produced. Because of high viscosity, primary recovery factors for heavy oils are generally low; if the viscosity is higher than 10,000 – 20,000 cP in situ and the permeability is less than 5 Darcy, it appears that commercial recovery using any conventional non-thermal method is not possible. With careful design and implementation, various thermal recovery schemes can be effective, but high operational costs restrict their applicability. Though it has been long recognized that "...the maximum recovery of oil from an unconsolidated sand is directly dependent upon the maximum recovery of the sand itself..., " CHOPS was not widely implemented with commercial success until advanced pumping systems (such as the progressive cavity pumps) were perfected in the late 1980's for slurries containing sand. Since then, because of reasonable recovery factors (~15 – 20%), production rates (3.2 – 47.7 m/day), effective sand handling and disposal and no heat costs, CHOPS has grown to provide more than 20% of Canada's oil. In 2002, Canada's oil production from all sources was approximately 460,000 m/d, of which more than 95,400 m/d was CHOPS production. Heavy oil reservoirs suitable for CHOPS are located in unconsolidated or weakly consolidated sands where sand mobilization can be easily triggered and sand influx sustained for the productive life of the well. Because of several unique characteristics of unconsolidated heavy oil reservoirs, well productivity may be 10 – 20 times higher in CHOPS wells than predicted by conventional Darcy's law flow equations. The mechanisms responsible for the enhanced production rate in CHOPS are:Porosity and permeability are enhanced as sand is removed from the formation, along with any mechanical skin that may have developed; The oil flow velocity relative to fixed coordinates is increased if the matrix is partially mobilized. Therefore, production rate increases, as predicted from Darcy's law;
- North America > United States (1.00)
- North America > Canada (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- South America (0.89)
- Oceania > New Zealand (0.89)
- Oceania > Australia (0.89)
- (4 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Cold heavy oil production (1.00)
Abstract Maximizing recovery factors requires careful assessment of many candidate technologies applied together (hybrid or mixed) or in a series of extraction phases (sequenced). Two major issues arise in sequencing technologies: first, understanding the physics and screening criteria of the options; second, understanding and exploiting the changes that the reservoir has experienced during previous phases. Sequencing of extraction technologies takes advantage of improvements in transport properties caused by different technologies. CHOPS increases the reservoir permeability, porosity and compressibility, as well as favorably altering the stress fields and shortening the flow path. These major improvements mean that thermal or gravity methods will be far more effective if applied after CHOPS, rather than as a first extraction phase. High-pressure thermal approaches such as SF, CSS or HCS generate a great deal of reservoir dilation, as well as viscosity reduction (T) and breaching of shaley flow barriers. These effects mean that gravity methods such as IGI and VAPEX have greater chances of success and will achieve increased extraction efficiency if used after these high-pressure steam methods. Once interwell communication is established by an approach such as CSS, conversion to drive methods or combined drive and gravity drainage approaches is feasible. Also, massive dilation during cyclic injection phases means that recompaction drive mechanisms can be counted on to improve recovery rates and recovery factors. ISC (combustion) in long or short flow path configurations could have far greater chances of success if used as a final "stripping" technology once a reservoir has been dilated, heated, and depleted by other methods. A possible vertical well sequence is CHOPS _ CSS _ SF _ IGI, perhaps even terminating with a ISC phase. A horizontal well sequence of CP _ HCS _ SAGD _ IGI _ ISC may be feasible. At the very least, a phase of CHOPS, if it can be achieved, will improve reservoir transport properties for most other production technologies. Because CHOPS is limited to vertical wells, this leads to ideas involving combinations of vertical and horizontal well arrays, such as CHOPS and HCS executed simultaneously, followed by conversion to SAGD once communication is established, then IGI and perhaps ISC as stripper phases. In the presence of active water or gas zones, options are more limited because of channeling and coning, but there still remain sequencing possibilities for low Δp (gravity drainage) approaches exploiting reservoir changes. Planning for sequencing of production options from the beginning of a project will reduce costs in many ways, as well as prolonging the asset life and increasing the ultimate recovery factor. The impact on technically recoverable reserves estimates in heavy oil will be huge if sequencing is properly implemented. Recoverable reserves increases exceeding a trillion barrels are expected. Introduction The Viscous Oil Resource Since the early 1980's, a number of new production technologies has been introduced to the oil industry. Under the right set of reservoir conditions and fluid properties, each of these technologies can bring additional value by increasing the Recovery Factor (RF), reducing costs, or accelerating production rate.
- North America > United States (0.67)
- North America > Canada (0.47)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock (0.95)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.34)
- North America > Canada (0.89)
- Europe > Russia > Northwestern Federal District > Komi Republic > Timan-Pechora Basin > Pechora-Kolva Basin > Usa Field (0.89)
Abstract Sand Management is an operating concept where traditional sand control means are not normally applied, and production is managed through monitoring and control of well pressures, fluid rates and sand influx. In the last four years, Sand Management in conventional oil and gas production has been implemented on a large number of wells in the North Sea and elsewhere. In almost all cases it has proven to be workable, and has led to the generation of highly favorable well skins because of self-cleanup associated with the episodic sand bursts that take place. These low skins have, in turn, led to higher productivity indexes, and each of the wells where sand management has been successful has displayed increased oil or gas production rates. Furthermore, expensive sand control devices are avoided and the feasibility of possible future well interventions is guaranteed. Different analysis and design tools are needed to evaluate sand production probability, to quantify risk reduction, and to establish practical operational criteria for safe and optimum production. Such design tools include the capacity to predict sand production onset, sand quantities and sand production rates, equipment erosion risks, and the conditions at which the sand can be transported inside the production liner and surface lines. Also, an essential tool is a sand monitoring technology to allow real-time quantitative sand flux tracking. The application of these tools and how they help assess risks in Sand Management are illustrated through field examples in this paper. Methods of handling the uncertainties and risks are discussed. Data from the North Sea, where active Sand Management was applied to increase well production rates, are presented. Finally, ideas on how to apply sand management and hybrid completions in challenging environments such as HPHT fields, marginal fields and complex structures are discussed. Introduction This review of the tools of Sand Management is an introduction to the Sand Management approach for optimization of production rates and well productivity. Because of the drawbacks of classical sand control techniques and the risks involved in uncontrolled sand production, Sand Management is proposed as a synthesis of the two philosophies. Furthermore, the challenges of developing complex, marginal and HPHT fields require new solutions. Historical steps in preventing sand production risk. Classical sand control techniques, such as gravel packing, wire wrapped screens, frac-and-pack, chemical consolidation, expandable screens, etc., are based on a sand exclusion philosophy: absolutely no sand in the production facilities can be tolerated. Alternatively, in the absence of means of totally excluding sand influx, the traditional approach is to reduce the production rate to minimise the amount of entering sand. The decision to exclude or control sand is based on a sand prediction analysis, for example, where the suitability of a perforated liner solution is evaluated based on a no-sand condition [1]. This has led to development of various techniques to predict the onset of sand production [2 – 5]. Thus, sand influx is usually viewed as a factor that limits the production rate (and thereby the cash-flow) through the induced production limitations set by installed sand control methods, production losses due to failures and workovers, and induced production restrictions arising from low maximum sand-free rate limits.
- North America > United States > Texas (0.68)
- Europe > Norway > North Sea (0.56)
- Europe > United Kingdom > North Sea (0.46)
- (2 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.67)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Sleipner Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Skagerrak Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Hugin Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Heather Formation (0.99)
ABSTRACT: This paper summarizes some results of detailed geotechnical studies on two shales: Queenston and Pierre I. The emphasis is on physical and mechanical properties of these shales under typical stress and moisture content conditions encountered in petroleum boreholes. Included is mineralogy, changes in moisture content with relative humidity, swelling potential, p-wave velocities under low-stress conditions, and mechanical properties. The effect of moisture content on strength has been also investigated. Hydrostatic and triaxial compression tests performed on the Queenston shale have been designed to gather data necessary for non-linear modelling of borehole stresses. RÉSUMÉ: Des etudes geomecaniques à profondeur sur deux argiles, Queenston et Pierre I, sont detaillees ici-dans. Les proprietes physico-mecaniques sous contraintes et de teneurs en eau characteristiques des conditions rencontrees dans les forages petrolieres ont ete etudiees, y inclus le gonflage, la reponse dielectrique, la mineralogic, les velocites aooustiques compressionelles et en cisaillement, etc. Pour I'argile gonflante, le Pierre I, la relation entre le teneur en eau et la resistance compressionelle etait delimitee, Plusieurs essais triaxiaux sous des chemins de contraintes varies etaient utilises pour etudier les effets non-lineaires de I'argile Queenston, en vue de faire des calculations de stabilite pour des forages petrolieres. ZUSAMMENFASSUNG: In vorliegendem Bericht wurden manche Ergebnisse der geotechnischen Untersuchungen vorgestellt, die auf zwei Schiefergesteinen durchgefuehrt wurden: Queenston und Pierre 1. Der Nachdruck wurde auf die mechanischen Eigenschaften der Schiefer bei den typischen Spannungsfeldem und der Feuchtigkeit gelegt, die in den Erdölbohrlöchem zu treffen sind. Man hat beruecksichtigt: mineralogische Angaben, Änderungen der Feuchtigkeit bei angegebener relative Feuchte, Aufquellung und Geschwindigkeit der P-Welle bei schwachen Spannungen und mechanische Eigenschaften. Es wurde auch der Einfluß der Feuchtigkeit auf die Bestandigkeit ueberprueft. Das Ziel der Proben des dreiachsigen Drucks, die auf den Schiefem aus Queenston durchgefuehrt wurden, war das Sammeln der Daten, die zum nichtlinearen Modellieren der Spannungen in der Tietbohrung notwendig sind. INTRODUCTION Almost all borehole instability problems encountered in shale formations are related to mechanical degradation, which is related to natural stress, pressure, temperature, and mechanical and geochemical properties, combined with mud filtrate land shale electrochemical interactions. These lead to alterations in mechanical response during drilling, changed stress distributions, and variations in pore pressures. As part of a larger goal of better understanding shales in the deep borehole environment, the Pierre I and the Queenston Shale (PS and QS) have been studied at the University of Waterloo. Pierre I is a swelling shale, whereas Queenston is a non-swelling shale; geochemistry is more vital in the former, mechanics in the latter. Herein, we focus on shale physico-mechanical properties, using results of different tests. BACKGROUND MATERIAL The PS was chosen as an end member of the swelling (gumbo, smectitic) shales that are encountered m drilling, often resulting in stuck pipe. It has a clay/quartz ratio of 4.7. The non-swelling QS was chosen because wellbore instability problems, particularly massive spalling, are often encountered in quartz-illite shales. The PS is a "shallow quarry" or "outcrop" Upper Cretaceous marine shale from the Great Plains of the northwestern United States (Chenevert, 1990; McKown et a1., 1982).
- North America > United States (0.34)
- North America > Canada (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Europe > Norway > Barents Sea > Stø Formation (0.98)
- North America > United States > South Dakota > Pierre Field (0.93)
Introduction Large-scale fracturing, fire floods, or hot water injection can alter principal stress magnitudes () and directions, even at the reservoir scale. In fracturing, this leads to changes in fracture orientation (Dusseault and Simmons, 1982); in firefloods, stress changes lead to yield and microseismic emissions, impairment of reservoir seal, and well loss through shear (Dusseauh et al., 1988); hot or cold water injection can induce shear failure or tensile stress zones around the injection borehole (Hojka et al., 1993). Pore pressure changes also alter total and effective stresses (), and sand production or sand injection will lead to reservoir-scale stress changes (Dusseault and Santarelli, 1989). This article addresses stress changes during thermal operations. Thermal loading is often a non-linear problem because reservoir response is modified:* principal stress fields are rotated and altered;* volume changes occur and stresses change;* yield and dilation of the reservoir occurs;* absolute and relative permeability changes because of dilation and saturation alteration;* bounding strata properties may be affected by tensile cracking orshear yield; and,* overburden or reservoir shearing develops because of high porepressures, thermal stresses, and weakening due to yield. These factors, combined with parameter uncertainty and limited in situ information, mean that analyses must be viewed as qualitative, no matter how sophisticated and precise the model. Useful conceptual models can nonetheless be developed using simple but realistic assumptions, and elastic models aid understanding. At the reservoir scale, no-lateral- strain models are instructive. At a slightly smaller scale, understanding stiff or soft inclusion behaviour in a changing stress field, or expanding or contracting inclusion behaviour in a constant stress field, will help in developing conceptual models to explain various effects in petroleum engineering that arise because of redistribution of stresses. STRESS CHANGES: A SIMPLE MODEL Figure 1 represents a permeable reservoir at initial stress conditions pore pressure u, and temperature T.. Principal stresses correspond to vertical and horizontal directions. Assuming linear elastic behaviour, Hooke's Law is: (1) E, and are Young's modulus, Poisson's ratio, and the coefficient of linear thermoelastic expansion. The stress-strain law is written in terms of effective stress changes; Terzaghi's effective stress law is assumed to apply for incremental principal stress changes (): (2) where (is Biot's parameter; (= 1.0 in this analysis. P. 319^
- North America > United States (0.28)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.54)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.98)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.98)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)