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SPE/EAGE European Unconventional Resources Conference & Exhibition - From Potential to Production
- Conference date: 20 Mar 2012 - 22 Mar 2012
- Location: Vienna, Austria
- Published: 20 March 2012
41 - 60 of 74 results
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Visualizing Stress Trajectories around Pressurized Wellbores
Authors Ruud Weijermars and Dan Schultz-ElaA new approach, using stress functions, reveals how each component of the stress regime affects the stress pattern around the wellbore. The effect of tectonic far field stress on the stress trajectories in the host rock near a wellbore is visualized in a series of plots with the analytical stress trajectory solutions for a large range of net pressures on the wellbore. The deviatoric stresses around a wellbore result from the dynamic superposition of (1) far field tectonic stress, (2) near wellbore stress due to lithostatic pressure near the open hole, (3) pore over-pressure or under-pressure in the host rock, and (4) hydraulic pressure applied on the wellbore. The principal stress trajectory plots are used to determine the suitable options for well orientations and to delineate stress trajectory control of the incipient brittle failure patterns for hydrofracs and wellbore breakouts. Our approach provides fundamental insight, with an important practical application for improved understanding of the growth of hydrofractures.
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Water Management and Microbial Control Programs in the Exploitation of Unconventional Hydrocarbons
Worldwide, the production of natural gas and now oil from shale basins (source rock) has been embraced as a commercially viable way of producing unconventional energy resources leading to a revolution in gas production in the US. Developments to invest in and tap into this alternative way of gas production are taking off in Europe and Asia. Hydraulic fracturing is a proven technology, used for many years to develop hydrocarbon resources. Successful strategies with hydraulic fracturing include the safe and effective use of chemical additives, proper well casing and robust water management programs. During the exploitation of hydrocarbons from shales, chemical additives such as corrosion inhibitors, gelling agents, biocides etc, have to be used in the fracturing of wells. Sustainable chemistries and effective product stewardship programs are required to minimize environmental and human exposure hazards. The addition of water with organic molecules to the actual fractured wells makes these environments subject to unwanted growth of microorganisms and biofilm development, which has detrimental effects on hydrocarbon flow and leads to pipeline/equipment corrosion. Often the presence of sulfate reducing microorganisms leads to unwanted H2S production and subsequently souring. Due to this, water cycle management and properly designed microbial control programs for all water sources including injected water or produced water, are required. Because the microbial challenges and environmental parameters of these water sources vary, different microbial control strategies and treatments are required for each source. New formulations of biocides and control programs aimed at the needs of the gas and oil industry have been developed, e.g. improved heat stability and the reduction in biocide levels to achieve the same level of microbial control. These newly developed microbial control technologies will be presented in this paper, and the related regulatory and product stewardship support will be shortly addressed.
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Exploring Shale Basins using Existing Wells
Authors Jason Pitcher, Shan Kwong, Jeffrey Yarus and Mike MullenIn the search for unconventional shale plays with commercial potential, many operators have properties in petroprovince basins containing wells through potentially productive shale zones. These shales were often encountered as part of exploration or development programs for deeper conventional targets. Often, the overlying shale is known to have had gas or oil shows reported during initial drilling, but little or no additional geological data was acquired at the time. This paper discusses the workflow and method to use the minimal information from these existing wells, and to quantitatively incorporate them into a basin exploration program. The process begins with a single new well, such as a sidetrack from an existing well, which is evaluated with the full array of open hole logging tools. Coring (conventional or sidewall), DFIT tests, and other shale-specific logging tools are performed on this initial well. Pre-existing wells that penetrate the objective shale can also be quantitatively assessed for relevant shale properties by using specialized logging tools, such as a combined through-casing pulsed neutron and sonic tool, to map relevant shale properties. These tools are calibrated to the open hole data to generate a wider distribution of data points containing critical shale properties that can be demonstrated to have a strong relationship with production. After the data acquisition process has been performed, the data are combined with existing seismic and structural information to delineate the best areas for further evaluation. Using modern mapping tools, a basin can be rapidly appraised to identify sweet spots, providing further exploration targets for evaluation drilling. This paper discusses limitations, best practices, workflows, and methods, and includes an example of a European shale evaluation log to demonstrate this exploration technique.
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Geosteering in Unconventional Shales: Current Practice and Developing Methodologies
Authors Jason Pitcher and Tavia JacksonCurrent well placement in unconventional shale ranges from simple geometric well placement to a gamut of patternrecognition systems and geosteering with geochemical and geomechanical analyses. The wide diversity of systems used leads to uncertainty in the effectiveness of any strategy, with confusion as to the true value or merit of a particular technique. Often, a well-placement strategy is based on what came before, with little regard as to the complexities or differences between reservoirs. This paper reviews the current common practices used in geosteering in shales, for both gas- and oil-producing reservoirs. A brief history of strategy development is outlined, with comments about its perceived effectiveness and value. Examples of successes and failures are examined to attempt to determine the viability of a particular strategy. Finally, alternative approaches and methodologies are reviewed and examined, with comments about the potential application, benefits, and value.
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Microseismic Monitoring of Fracture Networks During Hydraulic Stimulation: Beyond Event Locations
Authors J-M. Kendall, J. P. Verdon, A. Baird, A. Wuestefeld and J. T. RutledgeThe successful exploitation of tight-gas reservoirs requires fracture networks, sometimes naturally occurring, often hydraulically stimulated. Borehole microseismic data acquired in such environments hold great promise for characterising such fractures or sweet spots. The loci of seismic events delineate active faults and reveal fracture development in response to stimulation. However, a great deal more can be extracted from these microseismic data. For example, inversions of shear-wave splitting data provide a robust means of mapping fracture densities and preferred orientations, useful information for drilling programs. They can also be used to track temporal variations in fracture compliances, which are indicative of fluid flow and enhanced permeability in response to stimulation. Furthermore, the frequency-dependent nature of shear-wave splitting is very sensitive to size of fractures and their fluidfill composition. Here we demonstrate the feasibility of using such analysis of shear-wave splitting measurements on data acquired during hydraulic stimulation of a tight-gas sandstone in the Cotton Valley field in Carthage, West Texas.
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Permeability Upscaling for Carbonates from the Pore-Scale Using Multi-Scale Xray-CT Images
Authors A.D. Khalili, C.H. Arns, J.-Y. Arns, F. Hussain, Y. Cinar, W.V. Pinczewski, S. Latham and J. Funkbility due to large permeability contrasts. The most accurate upscaling technique is employing Darcy’s law. A key part of the study is the establishment of porosity transforms between highresolution and low-resolution images to arrive at a calibrated porosity map to constraint permeability estimates for the whole core.
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Shale Plays in The Netherlands
Authors Sander Bouw and Jan LutgertThe Netherlands is a mature hydrocarbon province. EBN, the Dutch state participant for hydrocarbon exploitation and exploration, has identified shale plays as one of the contributors to add reserves and to maintain production at the current level. The main source rock for the limited amount of oil accumulations in The Netherlands are the Lower Jurassic (Toarcian) oil-prone shales. Lower Carboniferous (Namurian) hot shales have often been suggested as possible contributor to oil and gas Formation in The Netherlands as well, but this has not been proven to date. Recent discoveries of gas in the time-equivalent Bowland shales in the UK have encouraged interest in the production potential of these shales in North-western Europe. In this paper the geological and geomechanical properties of the Lower Jurassic and Lower Carboniferous are presented in a shale play context. The assessment methodology is subdivided in three sections: 1) the overall geology of the play, 2) the type and quantification of hydrocarbons present and 3) the production characteristics. New and specific measurements on core and cutting material include pyrolysis, methane adsorption, mineralogy, texture, porosity, permeability, static and dynamic geomechanical properties, hardness and fracture conductivity. The two identified plays show very distinctive properties. The Lower Jurassic samples indicate to be mostly thermally immature for dry gas implying that liquids can be expected. The Lower Carboniferous samples show areas that are overcooked. Mineralogical and geomechanical data suggest that different stimulation strategies may be necessary for these two plays to produce hydrocarbons effectively. The source rocks of Lower Jurassic age qualify as relatively soft while the Lower Carboniferous shales with high TOC content classify as very hard. Comparing the results of the assessment to known shale plays in the US, the plays position themselves in the opposite extremes of the productive shale play spectrum.
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After a Decade of Microseismic Monitoring: Can We Evaluate Stimulation Effectiveness and Design Better Stimulations
Authors Andreas Wuestefeld, Ted Urbancic, Adam Baig and Marc PrinceOver the past decade, microsesimic monitoring has become the approach most oftenused to gain an in-situ understanding of the rock's response during hydraulic fracture stimulations. From initial monitoring performed in the Barnett Shale to monitoring currently being carried out for example in the Horn River and Marcellus formations, we review the evolution of microseismic monitoring from the viewpoint of data collection (single versus multi-well array configurations, utilization of long lateral stimulation wells), to data analysis, to the incorporation of microseismic parameters to constrain and validate reservoir models. Generally, we have observed that overall fracture height, width and length, orientation, and growth vary from formation to formation and within each formation, thereby highlighting the ongoing necessity for microseismic monitoring. Additionally, through the use of advanced microseismic analysis techniques, such as Seismic Moment Tensor Inversion (SMTI), details on rupture mechanisms have been used to assess stimulation effectiveness, define complex Discrete Fracture Networks (DFN) and provide estimates of Enhanced Fluid Flow (EFF), which assist in calibrating and validating reservoir models. Utilizing spatial and temporal distributions in DFN and EFF, along with estimates of fracture interconnectivity and complexity, the role of pre-existing fractures and fault structures in the rock matrix can be established and used to provide more realistic estimates of stimulation parameters such as Stimulated Reservoir Volume (SRV).
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New Hydraulic Fracturing Process Enables Far-Field Diversion in Unconventional Reservoirs
Authors Fraser McNeil, Klaas van Gijtenbeek and Mark van DomelenThe challenge in recovering hydrocarbons from shale rock is its very low permeability, which requires cost-effective fracturestimulation treatments to make production economic. Technological advances and improved operational efficiency have made production from shale resources around the globe far more viable; however, while the wells being completed today are proving to be reasonably economical, the question that remains is if the operators are truly capitalizing on their full potential. In recent years, the industry has been in search of a better method to enable well operators to capitalize on the natural fractures commonly found in shale reservoirs. If properly developed, these natural fractures will create a network of connectivity within the reservoir, potentially improving long-term production when they have been propagated. In most shales, however, the stress anisotropy present can prevent sufficient dilation of the natural fractures during stimulation treatments. To induce branch fracturing, far-field diversion must be achieved inside the fracture to overcome the stresses in the rock holding the natural fractures closed. Increasing net pressure during the treatment will enhance dilation of these natural fractures, creating a complex network of connectivity, and the greater the net pressure within the hydraulic fracture, the more fracture complexity created. Most of the various processes introduced previously are limited because multiple perforated intervals or large open annular sections are treated at one time. Also, to achieve the high injection rates required, they are treated down the casing, so that any changes made to the treatment require an entire casing volume to be pumped before these changes reach the perforations. This paper presents a case history of a multistage-fracturing process that allows real-time changes to be made downhole in response to observed treating pressure. This functionality enables far-field reservoir diversion to be achieved, ultimately increasing stimulated reservoir contact (SRC).
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Shale Reservoir Properties from Digital Rock Physics
Authors Joel D. Walls, Elizabeth Diaz and Timothy CavanaughA majority of the whole core samples recovered in the US today come from shale reservoirs. A primary reason for so much shale coring is that shale well log analysis requires rigorous core calibration to provide reliable data for reservoir quality, hydrocarbon-in-place, and hydraulic fracturing potential. However, the uncertainty in interpreting shale well log data is sometimes matched or exceeded by the uncertainty observed in traditional methods of analyzing core samples. Most commercial core analysis methods in use today were developed originally for sandstones and carbonates exceeding 1 millidarcy in permeability. High quality, organic-rich shale on the other hand is usually lower than 0.001 millidarcy. This extremely low permeability creates substantial challenges for existing methods and has contributed to the rapid rise of a new approach to reservoir evaluation called Digital Rock Physics (DRP). DRP merges three key technologies that have evolved rapidly over the last decade. One is high resolution diagnostic imaging methods that permit detailed examination of the internal structure of rock samples over a wide range of scales. The second is advanced numerical methods for simulating complex physical phenomenon and the third is high speed, massively parallel computation using powerful graphical processing units (GPUs) that were originally developed for computer gaming and animation. Based on pore-scale images from a wide range of organic shales, it can be seen that organic material is present in a variety of forms. Three primary forms of organic matter are commonly observed; non-porous, spongy, and pendular. Non-porous organic components fill all of the available non-mineral space leaving virtually no porosity or fluid flow path. Porous or “spongy” organic material is commonly encountered in thermally mature gas shales. Pendular organic material appears to fill the small inter-granular and grain contact regions, leaving open pore space in the larger voids. These pore types are largely controlled by kerogen type and thermal maturity, and they exert large influence on the porosity, permeability, and overall shale reservoir quality.
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Impact of Geomechanics on Microseismicity
Authors Karn Agarwal, Michael J. Mayerhofer and Norman R. WarpinskiThe proper interpretation of microseismic event patterns to estimate hydraulic-fracture geometries is critical for understanding well performance in unconventional reservoirs. Besides factors such as microseismic event location uncertainty, advanced interpretations should also include a proper understanding of the geomechanical context in which these events take place and the underlying mechanisms that link the hydraulic fracture to the microseismic events. In this paper we investigate the different mechanisms that can cause microseismic activity around a hydraulic fracture from the viewpoint of a 3D elasto-static model to explain the behavior of microseismic event patterns. Stress perturbations caused by the opening of hydraulic fractures, opening of extensional branch fractures, and leakoff-related effects are considered. Multiple transverse fractures as well as dilated natural fractures orthogonal to the hydraulic-fracture direction are modeled under different sets of reservoir and treatment conditions to gain insight into the importance of different mechanisms. An important observation is that stress changes alone caused by tensile opening behind the hydraulic-fracture tip cannot cause microseismic events under any set of reservoir conditions normally encountered in practice. The results indicate that tip effects, propagation of extensional branch fractures, and activation of natural fractures upon intersection should be the main drivers of microseismic activity in shale-gas plays. The modeling shows that microseismic events are expected to occur very close to the hydraulically activated fractures or planes, thus enhancing the value of microseismic monitoring. The modeling also showed that under certain conditions (critically stressed formations), the shear zone caused by tip effects can extend fairly far ahead of the fracture tip, which needs to be considered in the interpretation of fracture geometry. The presented results help to constrain and enhance the interpretation of microseismic data, from a geomechanical perspective.
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Improving Completion and Stimulation Effectiveness in Unconventional Reservoirs – Field Results in the Eagle Ford Shale of North America
Authors C. D. Pope, Terry Palisch and Pedro SaldungarayIn an unconventional reservoir, the success of a project is driven by the completion. Unconventional plays have become the primary area of development in the US, and shale formations dominate the current rig activity. Most shale wells are drilled utilizing long horizontal wellbores, and completed using cemented or uncemented casing strings. To be economic, they require large hydraulic fracture treatments in multiple stages along the lateral. Total well costs are driven by the cost of fracturing, often representing as much as 60% of the total well cost. This requires the operator to select the best completion method which includes casing and wellhead selection that is based on stimulation needs. The stimulation is regulated by injection rates, treating pressures, the volume of the stimulation, type of fluid, proppant selection, perforations, and the number of stages. This paper focuses on several areas that are critical in a successful completion such as: casing size and pressure rating, wellhead selection, treatment design, spacing of the perforations and stages, linear verses cross-linked fluid, and the impact of proppant selection. With over 1800 wells completed and stimulated so far, a comparison of successful treatments and the cause of unsuccessful treatments will be provided. A review of actual field applications will be presented where possible, and a method for identifying best completion practices will be discussed. Those working in or considering developments in unconventional plays around the world will be able to compare their current completion techniques to those presented in the paper. In addition, while no two resource plays are the same, the findings in this paper can be used by engineers as a guide for moving up the learning curve more quickly in other unconventional plays.
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Can We Achieve Acceptable Fracture Conductivity Using WaterFracs?
More LessAfter 1970, the technology of hydraulic fracturing began to quickly accelerate, especially as to the industry focus on fracture conductivity. We saw a transformation in our frac fluids as we moved away from crudes and thin water gels to higher viscosity emulsion systems, foamed gels, and even crosslinked gel systems that could deliver significantly more proppant as we chased after better fracture conductivity. Using these more viscous gels we moved to “Massive Hydraulic Fracturing” of tight gas sand formations. This grew to multi-million pound proppant placements as the age of crosslinked gels began to dominate most of the fracture stimulation landscape as we tried to place very long, highly conductive fractures. However, the decade of the 1970’s also had Claude Cooke showing us that sand was a very limited proppant for deeper wells, and then later showing that gel residue could seriously reduce insitu fracture conductivities! (Cooke 1973; 1975; 1976; 1977) During the early 1980’s North America experienced the greatest rig activity ever, but then the mid-80’s gave us the greatest crash the oilfield had ever seen! Fortunately, this also resulted in our industry laboratories having the time to upgrade testing equipment and procedures to “realistic” test conditions for evaluation of packed proppant bed conductivity. This meant longer testing times, high temperatures, and with exposure to frac fluids. This research would subsequently launch the search for better gel breakers and lower residue gels (which continues today). Unexpectedly, in the 1990’s a few operators in tight sandstone applications in East Texas started re-inventing Slick Water fracs (WaterFracs), placing only 15-20% as much proppant as crosslink gel fracs, yet claiming equal or better overall economics. To add further consternation, George Mitchell found another application for WaterFracs and eventually showed the world that a hydrocarbon-source shale formation, the Barnett, can actually be a commercial producer itself. During the early 2000’s, the combination of long horizontals, and extreme multi-stage hydraulic fracturing (mostly using Waterfracs) turned the Barnett Shale into the launching pad of our present-day madhouse search for the next great shale play to chase. It is clear that long horizontal completions and WaterFrac stimulation methods have played an important role in opening the door to economic success in the numerous “resource plays” (i.e. shales). In this paper we will investigate if WaterFrac treatments are violating or upholding (?) one of our most significant fracturing beliefs: Fracture Conductivity should be optimized. Until we moved to the ultra-low formation permeabilities, we would generally say we should try to maximize our conductivity, but with WaterFracs designs it often seems we may instead be minimizing it, and this will be discussed here.
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Probabilistic Reserves and Resources Estimation: A Methodology for Aggregating Probabilistic Petroleum Reserves and Resources
Authors M. Galvao, L. Hastenreiter, J. Molina, A. Quadros, J. Montechiari and S. HamacherThe oil industry strives to create an international standard for classification and estimation of resources since the 1930s. The goal is to provide investors with information obtained under the same assumptions, as to facilitate the comparison between petroleum companies. In 2007 the four major international organizations, Society of Petroleum Engineers (SPE), American Association of Petroleum Geologists (AAPG), World Petroleum Council (WPC) and Society of Petroleum Evaluation Engineers (SPEE), jointly released a single set of guidelines for classification and evaluation of oil and gas resources, the Petroleum Resources Management System (PRMS, 2007). Several methodologies for estimating reserves can be employed within the PRMS’s (2007) premises, which can be classified as deterministic or probabilistic. Unconventional resources emerge as a new frontier for the oil industry, thus implying high uncertainty levels in both technical and economic assessments. The main purpose of this paper is to explore this issue and to propose a correlation-based probabilistic methodology for aggregating oil and gas reserves of conventional and unconventional resources. The methodology is in accordance with the guidelines of the PRMS (2007) and with the new rules of the Securities Exchange Commission 2009 (SEC). The correlation assessment evaluates technical and operational features, and the probabilistic aggregation is performed by Monte Carlo Simulation (MCS). Besides the introductory section, this paper comprises four other sections. A literature review presents definitions of conventional and unconventional resources, and an examination of classification, estimation and aggregation of reserves, important for better understanding the following sections. The third section describes the proposed correlation-based probabilistic methodology. Afterward, a case study presents an application of the methodology. Finally, the last section synthesizes the main conclusions.
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Novel Water Based Mud for Shale Gas, Part II: Mud Formulations and Performance
Shale-gas plays and other unconventional resources have gained significant importance worldwide. Historically, synthetic based drilling fluids (SBM) are used in these plays when no environmental concerns are in place and are preferred when wellbore stability is necessary. In this paper, we study the use of an improved water based drilling fluid (WBM) that is simple in formulation and maintenance that shows excellent rheological properties, maintains wellbore stability, and a good environmental profile. A combination of well-known and economically affordable materials is combined with new technology to achieve desired rheological properties and wellbore stability. The use of nanoparticles to decrease shale permeability by physically plugging nanoscale pores holds the potential to remove a major hurdle in confidently applying water-based drilling fluids in shale formations, adding a new advantage to the studied fluid. Silica nanomaterials were investigated for this purpose. Due to their commercial availability, these materials can be engineered to meet the specifications of the formation. Characterization of the nanoparticles was completed with Transmission Electron Microscopy (TEM), dynamic light scattering, and X-ray-photoelectron spectroscopy. Rheological properties and fluid loss are studied together with other important properties such as shale stability and anti-accretion properties. The authors will describe new laboratory methods used to investigate these properties, from a modified API fluid loss test to the Shale Membrane Test that measures both fluid loss and plugging effects and illustrate additional future research that includes adding reactive species, and anchoring them to the pores, thus stabilizing the shale further.
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Real-Time Downhole Monitoring of Hydraulic Fracturing Treatments Using Fibre Optic Distributed Temperature and Acoustic Sensing
Authors Mathieu M. Molenaar, Erkan Fidan and David J. HillIn order to make commercial and development decisions effectively and more rapidly, new appraisal and testing technologies are needed to maximize early data collection and subsequent subsurface understanding as quickly as possible. For Unconventional Gas and Light Tight Oil (UGLTO) projects, some of this critical data can be derived from hydraulic fracture stimulation and inflow profiling activities. For UGLTO projects, achieving an optimum hydraulic fracture stimulation is a continuous endeavor beginning as early as possible; and balancing the cost of completion vs. production performance is critical as the completion/stimulation is a large cost component of the well and heavily influences production rate/ultimate recovery. The fast paced development and introduction of new completion technologies requires diagnostic technology that can help us understand stimulation effectiveness, assess new completion technologies, and evaluate which zones are the most productive. One emerging technology, fibre optic distributed sensing has the potential of providing key insights during both the hydraulic fracturing and initial flowback. The passive nature of fibre optic sensors allows intervention-free surveillance, which makes fibre-optic technology an effective platform for permanent sensing in producing wells. Until recently, the oil & gas industry fibre optic sensing technology has focused mainly on temperature (DTS) profiling along the wellbore. In 2009, it was first demonstrated how fibre optic distributed acoustic sensing (DAS) can also be used for downhole applications. Where hydraulic fracture diagnostics based on DTS alone in the past sometimes yielded ambiguous results, the combination of both acoustic and temperature sensing provides a step-change improvement in the ability to perform real-time and post-job diagnostics & analyses of the stimulation. The different horizontal well case studies presented in this paper will illustrate how the combination of DTS and DAS has the potential to enhance the monitoring, assessment, and optimization of openhole and limited entry designed hydraulic fracture stimulation treatments.
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3D Seismic as an Aid to Design Syngas Production by Means of Underground Coal Gasification (UCG) Methodology
Authors Dries du Plooy, Béla Szanyi, Jenő Mázik, Péter Majoros, Tamás Tóth, Zoltán Kádi and Balázs KoroknaiThe unconventional use of coal to supplement Natural Gas (NG) in the power and chemical industry makes Underground Coal Gasification (UCG) an important technology in economically producing unconventional gas. Present day exploration and production technologies pave the way “from a potential to actual production”. A 3D seismic survey has been applied in Southern Hungary for the site selection of UCG resource blocks, as well as in the design of the most optimal exploration drilling program. The latter exploration techniques directional drilled injection and production wells are planned in the coal seams to sustain the burning front. Wildhorse UCG Kft is a pioneer in the design and introduction of the environmentally friendly coal based syngas for electric power generation in East-Central European countries. Additionally the Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE/EAGE European Unconventional Resources Conference and Exhibition held in Vienna, Austria, 20-22 March 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. syngas can be utilised to supplement national gas supplies as alternative fuel gas. In this presentation the role of 3D seismic is discussed in defining the “Mecseknádasd UCG project”. Wildhorse UCG Kft completed 3D seismic measurements in April and May of 2011 in the Mecseknádasd UCG project area. The goal of the seismic measurements is to image and clarify the structural conditions and to reveal faults and other discontinuities in the coal formation explored previously by historic deep drilling in the area. The processing and interpretation of the survey results have been performed together by GEOMEGA Kft and Wildhorse UCG Kft and the presentation covers the complete survey results of the Mecseknádasd UCG exploration project: − Newly processed results of historical boreholes − Results of the seismic survey − Geological and geophysical results of new boreholes − Possibilities for upgrading the geological model with integrated interpretation by using the available geophysical data (seismic, new boreholes, historic boreholes) − The possibilities for the application of 3D seismic survey in the design process of the UCG technology and to monitor the UCG engineering process
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Unconventional Reservoirs: Basic Petrophysical Concepts for Shale Gas
Authors Juan C. Glorioso and Aquiles RattiaUnconventional reservoirs have burst with considerable force in oil and gas production worldwide. Shale Gas is one of them, with intense activity taking place in regions like North America. To achieve commercial production, these reservoirs should be stimulated through massive hydraulic fracturing and, frequently, through horizontal wells as a mean to enhance productivity. In sedimentary terms, shales are fine-grained clastics rocks formed by consolidation of silts and clays. In log interpretation of conventional reservoirs, it is very common to observe that the clay parameters used to correct porosity and resistivity logs for clay effects are in fact read in shaly intervals rather than in pure clay. Although no considerable deviation have been observed in shaly sandstones, anyway these concepts and procedures must be reviewed to run log analysis in shale gas. Organic matter deposited with shales containing kerogen that matured as a result of overburden pressure and temperature, giving rise to source rocks that have yielded and expulsed hydrocarbons. Shale gas reservoir type is a source rock that has retained a portion of the hydrocarbon yielded during its geological history so that to evaluate the current hydrocarbon storage and production potential it is necessary to know the kerogen type and the level of TOC - total organic carbon - in the rock. Produced gas comes from both adsorbed gas in the organic matter and "free" gas trapped in the pores of the organic matter and in the inorganic portions of the matrix, i.e. quartz, calcite, dolomite. In these unconventional reservoirs, gas volumes are estimated through a combination of geochemical analysis and log interpretation techniques. TOC, desorbed total gas content, adsorption isotherms, and kerogen maturity among other things can be measured in cores, sidewall samples and cuttings, in the laboratory. These data are used to estimate total desorbed gas content and adsorbed gas content which is part of the total gas. Also in laboratory, porosity, grain density, water saturation, permeability, mineral composition and elastic modules of the rock are measured. Laboratory measurement uncertainty is high and consistency between different providers appears to be low, with serious suspicions that procedures followed by different laboratories are the source of such differences. The permeability is one of the most important parameters, but at the same time, one of the most difficult to measure reliably in a shale gas. Core calibrated porosity, mineral composition, water saturation and elastic modules can be obtained through electric and radioactive logs. All these information is used to estimate log derived total gas volume which results are also subject to a high degree of uncertainty that must be overcome. Once this key information is obtained, it is possible to estimate different gas in-situ volumes. Indeed, an estimate of porosity-resistivity based total gas in-situ and, on the other hand, geochemical based adsorbed gas in-situ can be performed. Log total gas in-situ can be, and it is advisable to do, compared with adsorbed gas estimations and also with another gas measurement called direct method - total gas desorption performed on formation samples. The difference between log total gas in-situ and adsorbed gas in situ should be the "free" gas in situ. Free gas occupies the pores of kerogen and matrix; also it can be stored in open natural fractures if such fractures are present. The main objective of this paper is to discuss the state-of-the-art in petrophysical evaluation of shale gas reservoirs, to summarize the experiences of operators and researchers, and to bring some views on the criteria and techniques for the evaluation of cores and logs. An inventory of laboratory tests and results, log responses in the presence of kerogen, log interpretation techniques and estimation methods for different volumes of gas in-situ, together with important aspects of the use of analogy in shale gas reservoirs has been done. At the end, a basic petrophysical workflow is outlined for the volumetric determination of gas in situ.
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Experimental Measurements of Mechanical Parameters of Class G Cement
Authors Catalin Teodoriu, Zhaoguang Yuan, Jerome Schubert and Mahmood AmaniThe new quest of unconventional resources is the achievement of well integrity which is highlighted by the inadequacy of conventional cementing procedures to provide zonal isolation. High temperatures and pressures or even post-cementing stresses imposed on the cement sheath as a result of casing pressure testing and formation integrity tests set in motion events which could compromise the long term integrity of the cement sheath due to fatigue. Knowledge of the mechanism of fatigue in cement and factors that affect it such as the magnitude of the load, strength and composition of the cement, mechanical properties of the cement and pattern of load cycles are important to achieve a realistic design of a cement system that will be subjected to fatigue loading. Such a design will go a long way to ensure the long term integrity of a well operating under downhole conditions. Finite element investigations help engineers to assess the stress magnitude and evolution for a given well configuration, but when structural calculations for casing-cement system are required, missing input parameters reduce the quality of the results. In order to have reliable data we performed an extensive experimental work using Class G cement in order to measure the principal parameters for mechanical structural calculations: compressive and tensile strength, Young modulus, Poison Ratio. The data was measured under room conditions and elevated temperature and pressure. The results were also extrapolated for a time period for more than 300 days. The paper will provide an excellent data inventory for class G cement that can be used when mechanical studies on cement, like finite element studies, are required.
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Study of Class G Cement Fatigue using Experimental Investigations
Authors Christian Kosinowski and Catalin TeodoriuThis paper presents the results of laboratory investigation about fatigue of Class G wellbore cement exposed to radial loads under room temperature conditions. While fatigue is well described for metals, wellbore cement fatigue is a rather unknown field. As well cements can be exposed to cyclic loading situations like in new oilfield technologies e.g. enhanced oil recovery by steam injection or geothermal applications using single-well-solutions, cement damage by fatigue becomes a more important issue. Cement integrity is crucial environmental and economic issue and no risk on cement failure should be accepted. The thermal induced loads in the reality were replaced by mechanical loads that recreates the stress situation on the cement. In order to evaluate the behavior of the cement, experiments were performed to investigate how cement reacts to cyclic loadings. A low number of cycles mean up to 100 loadings sequences. Samples of a pipe-cement-compound recreating the wellbore geometry are tested in a hydraulic press under axial loads. The stress situation in the cement sheath of the tested samples was calculated using a combination of numerical and analytical methods. Failure criteria were used to evaluate these calculations and could be used to predict future failure behavior. It has been found that fatigue of cement is rather similar for metal and cement at least in the low cycle range. For metals there is a specific stress limit where failure or significant damage to the material occurs within several cycles. This means, if the limit is exceeded the material will fail, maybe not at the first cycle, but it will fail over the cycles. Cement shows that this behavior is similar to metals, no other fatigue mechanisms like damage accumulation were observed, just a straight load limit.
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