Thesis (Ph. D.)--University of Texas at Austin, 2005. / Supervisors: Martin E. Chenevert and Mukul M. Sharma. Vita. Includes bibliographical references.

The horizontal well with multiple transverse fractures has proven to be an effective strategy for shale gas reservoir exploitation. Some operators are successfully producing shale oil using the same strategy. Due to its higher viscosity and eventual 2-phase flow conditions when the formation pressure drops below the oil bubble point pressure, shale oil is likely to be limited to lower recovery efficiency than shale gas. However, the recently discovered Eagle Ford shale formations is significantly over pressured, and initial formation pressure is well above the bubble point pressure in the oil window. This, coupled with successful hydraulic fracturing methodologies, is leading to commercial wells. This study evaluates the recovery potential for oil produced both above and below the bubble point pressure from very low permeability unconventional shale oil formations. We explain how the Eagle Ford shale is different from other shales such as the Barnett and others. Although, Eagle Ford shale produces oil, condensate and dry gas in different areas, our study focuses in the oil window of the Eagle Ford shale. We used the logarithmically gridded locally refined gridding scheme to properly model the flow in the hydraulic fracture, the flow from the fracture to the matrix and the flow in the matrix. The steep pressure and saturation changes near the hydraulic fractures are captured using this gridding scheme. We compare the modeled production of shale oil from the very low permeability reservoir to conventional reservoir flow behavior. We show how production behavior and recovery of oil from the low permeability shale formation is a function of the rock properties, formation fluid properties and the fracturing operations. The sensitivity studies illustrate the important parameters affecting shale oil production performance from the stimulated reservoir volume. The parameters studied in our work includes fracture spacing, fracture half-length, rock compressibility, critical gas saturation (for 2 phase flow below the bubble point of oil), flowing bottom-hole pressure, hydraulic fracture conductivity, and matrix permeability. The sensitivity studies show that placing fractures closely, increasing the fracture half-length, making higher conductive fractures leads to higher recovery of oil. Also, the thesis stresses the need to carry out the core analysis and other reservoir studies to capture the important rock and fluid parameters like the rock permeability and the critical gas saturation.

With increase of interest in exploiting shale gas/oil reservoirs with multiple stage fractured horizontal wells, complexity of production analysis and reservoir description have also increased. Different methods and models were used throughout the years to analyze these wells, such as using analytical solutions and simulation techniques. The analytical methods are more popular because they are faster and more accurate. The main objective of this paper is to present and demonstrate type curves for production data analysis of shale gas/oil wells using a Dual Porosity model. Production data of horizontally drilled shale gas/oil wells have been matched with developed type curves which vary with effective parameters. Once a good match is obtained, the well dual porosity parameters can be calculated. A computer program was developed for more simplified matching process and more accurate results. As an objective of this thesis, a type curve analytical method was presented with its application to field data. The results show a good match with the synthetic and field cases. The calculated parameters are close to those used on the synthetic models and field cases.

As the conventional reservoirs decrease in discovering, producing and reserving, unconventional reservoirs are more remarkable in terms of discovering, development and having more reserve. More fields have been discovered where Barnett Shale and Bakken Shale are the most recently unconventional reservoir examples. Shale reservoirs are typically considered self-sourcing and have very low permeability ranging from 10-100 nanodarcies. Over the past few decades, numerous research projects and developments have been studied, but it seems there is still some contention and misunderstanding surrounding shale reservoirs. One of the largest shale in the United State is the Bakken Shale play. This study will describe the primary geologic characteristics, field development history, reservoir properties,and especially production trends, over the Bakken Shale play. Data are available for over hundred wells from different companies. Most production data come from the Production Data Application (HDPI) database and in the format of monthly production for oil, water and gas. Additional 95 well data including daily production rate, completion, Pressure Volume Temperature (PVT), pressure data are given from companies who sponsor for this research study. This study finds that there are three Types of well production trends in the Bakken formation. Each decline curve characteristic has an important meaning to the production trend of the Bakken Shale play. In the Type I production trend, the reservoir pressure drops below bubble point pressure and gas releasingout of the solution. With the Type II production trend, oil flows linearly from the matrix into the fracture system, either natural fracture or hydraulic fracture. Reservoir pressure is higher than the bubble point pressure during the producing time and oil flows as a single phase throughout the production period of the well. A Type III production trend typically has scattering production data from wells with a different Type of trend. It is difficult to study this Type of behavior because of scattering data, which leads to erroneous interpretation for the analysis. These production Types, especially Types I and II will give a new type curve matches for shale oil wells above or below the bubble point.

Porous materials are implemented in several industrial applications such as water desalination, gas separation and pharmaceutical care which they are mainly governed by the pore size and the PSD. Analyzing shale reservoirs are not excluded from these applications and numerous advantages can be gained by evaluating the PSD of a given shale reservoir. Because of the limitations of the conventional characterization techniques, novel methods for characterizing the PSD have to be proposed in order to obtain better characterization results for the porous materials, in general, and shale rocks in particular. Thus, permporosimetry and evapoporometry (EP) technologies were introduced, designed and utilized for evaluating the two key parameters, pore size and pore size distribution. The pore size and PSD profiles of different shale samples from Norway and Argentina were analyzed using these technologies and then confirmed by mercury intrusion porosimeter (MIP). Norway samples showed an average pore diameter of 12.94 nm and 19.22 nm with an average diameter of 13.77 nm and 23.23 nm for Argentina samples using permporosimetry and EP respectively. Both techniques are therefore indicative of the heterogeneity of the shales. The results from permporosimetry are in good agreement with those obtained from MIP technique, but EP for most part over-estimates the average pore size. The divergence of EP results compared to permporosimetry results is referred to the fact that the latter technique measures only the active pores which is not the case with the former technique. Overall, both techniques are complementary to each other which the results from both techniques seem reasonable and reliable and provide two simple techniques to estimate the pore size and pore size distributions for shale rocks.

Shale oil (tight oil) is oil trapped in low permeability shale or sandstone. Shale oil is a resource with great potential as it is heavily supplementing oil production in the United States (U.S. Energy Information Administration, 2013). The shale rock must be stimulated using hydraulic fracturing before the production of shale oil. When the hydrocarbons are produced from fractured systems, the resulting flow is influenced by the fracture, the stimulated rock, and the matrix rock. The production decline rates from shale oil reservoirs experience flow regimes starting with fracture linear flow (fracture dominated), then bilinear flow (fracture and stimulated rock dominated), then formation linear flow (stimulated rock dominated), and finally pseudo-radial flow (unstimulated matrix rock dominated) (Cinco-Ley 1982). In this thesis, daily production rates from a shale oil reservoir are modeled using a simple spreadsheet-based, finite difference serial flow simulator that models the single-phase flow of a slightly-compressible oil. This simulator is equivalent to flow through multiple tanks (subsequent part of the thesis will call these cells) through which flow passes serially through one tank into the other. The simulator consists of 11 tanks. The user must specify the compressibility-pore volume product of each tank and the transmissibility that governs flow from one tank to another. The calculated rate was fitted to the given data using the Solver function in Excel. The fitted matches were excellent. Although we can adjust all 22 parameters (2 per cell) to affect the simulation results, we found that adjusting only the first three cells nearest to the well was sufficient. In many cases, only two cells were enough. Adjusting 4 or more cells resulted in non-unique matches. Furthermore, the properties of the very first cells proved insensitive to the matches when using the 3 cells to match the data. The cells in the 2 cell model represent the stimulated zone and the unstimulated rock. Likewise, the cells in the 3 cell model represent the hydraulic fracture, the stimulated zone, and the unstimulated rock. The accessed pore volume and transmissibility were responsive to the injected sand mass and fluid volume up to approximately 10⁶ kg and 7000 m³ respectively; injecting more sand and fluids than this caused negligible increases in the accessed pore volume and transmissibility. This observation suggests that the sand does not migrate far into the fractures. Similarly, it was observed that the number of stages was positively correlated with cell transmissibility and pore volume up to 20 stages. These results suggest that fracture treatments were significantly over designed and injecting less sand and water in fewer stages would optimize the economics of similar projects. To our knowledge this is the first work to analyze the results of fracture treatments by matching with pore volumes and transmissibility in a simple serial cell flow. / text

O presente trabalho consistiu na realização de um estudo geológico na porção norte da Bacia intracratônica do Paraná. O estudo buscou avaliar o potencial gerador e de exploração de shale gas e shale oil dos folhelhos negros da Formação Irati na região de Goiás e Mato Grosso, Centro-Oeste do Brasil, através da caracterização de geoquímica orgânica dos folhelhos, determinação do potencial gerador e grau de maturação da matéria orgânica dos folhelhos, caracterização das relações geológicas da formação, espessuras, áreas de ocorrência, alternância de camadas com carbonatos, profundidade de ocorrência, padrões de fraturamento, composição mineralógica e estimativa de reservas de shale gas tecnicamente recuperáveis. O trabalho contribui com uma metodologia que permite avaliar o potencial de geração e exploração de recursos de shale gas e shale oil. O estudo na temática de recursos energéticos não convencionais, com destaque para o shale gas, principal fonte de gás natural não convencional explorada no mundo, é de extrema importância, pois o gás natural é considerado um combustível de transição de uma matriz energética baseada em energias fósseis para uma matriz com predominância de energias renováveis, considerando-se os seus benefícios, tanto ambientais quanto em aspectos estratégicos e econômicos. Os valores de COT variam de 0,04 a 3,52% com média de 1,31%, o que lhes confere um bom potencial gerador de hidrocarbonetos na área de estudo. Foram encontrados valores no pico S2 que variam de 5,13 a 63,13 mg HC/g de rocha para a maioria das amostras estudadas pela pirólise Rock-Eval, conferindo-lhes um bom a excelente potencial petrolífero. Os folhelhos apresentam querogênio do tipo I, II e IV, com predomínio do querogênio do tipo II e IV. Estudos de maturidade térmica da matéria orgânica (querogênio) com base nos valores de Tmax, IH, IP e Ro, indicam seu grau como imaturo (com baixo nível de conversão em hidrocarbonetos) a supermaturo (zona de gás seco). Amostras que alcançaram a janela de geração de gás seco não possuem potencial para geração de hidrocarbonetos, uma vez que apresentam querogênio do tipo IV, que evidencia baixo poder de preservação da matéria orgânica durante o intenso magmatismo ocorrido no Mesozóico (Jurássico/Cretáceo). A maioria das amostras analisadas apresentam bom potencial para shale gas e/ou shale oil, porém as condições de temperatura e pressão durante a diagênese não foram suficientes para a maturação da matéria orgânica nos folhelhos. Os folhelhos possuem altos teores de quartzo e quantidades significativas de outros minerais tais como, o feldspato plagioclásio (albita), mica e carbonatos (calcita e dolomita), podendo responder favoravelmente à fraturamento hidráulico. A estimativa de reservas indica que a área de estudo poderia ter um potencial para cerca de 23 Trilhões de Pés Cúbicos de reservas de gás natural não comprovadas tecnicamente recuperáveis. / The present work consisted in the accomplishment of a geological study in the northern portion of the Intracratonic Basin of Paraná. The study aimed to evaluate the potential for shale gas and shale oil exploitation of the Irati Formation black shales in the region of Goiás and Mato Grosso, Mid-West of Brazil, through the characterization of organic geochemistry of shales, determination of the generating potential and degree of maturation of the organic matter of the shales, characterization of the geological relations of the formation, thicknesses, areas of occurrence, alternation of layers with carbonates, depth of occurrence, fracturing patterns, mineralogical composition and estimation of technically recoverable shale gas reserves. The work contributes with a methodology that allows to evaluate the potential of generation and exploitation of shale gas and shale oil resources. The study on the subject of unconventional energy resources, especially shale gas, the main source of unconventional natural gas explored in the world, is extremely important because natural gas is considered a transition fuel of a energy matrix based on energies fossils for a matrix with predominance of renewable energies, considering its benefits, both environmental and strategic and economic aspects. The TOC values vary from 0.04 to 3.52% with an average of 1.31%, which gives them a good hydrocarbon potential in the study area. S2 peak values ranging from 5.13 to 63.13 mg HC / g of rock were found for most of the samples studied by Rock-Eval pyrolysis, giving them a good excellent oil potential.The shales present type I, II and IV kerogen, with predominance of type II and IV kerogen. Thermal maturity studies of organic matter (kerogen) based on the values of Tmax, HI, PI and Ro, indicate their degree as immature (with low conversion level in hydrocarbons) to supermature (dry gas zone). Samples that reached the window of dry gas generation do not have potential for hydrocarbon generation, since they present type IV kerogen, which evidences low preservation power of organic matter during the intense magmatism occurring in the Mesozoic (Jurassic / Cretaceous). Most of the analyzed samples present good potential for shale gas and / or shale oil, but the conditions of temperature and pressure during diagenesis were not sufficient for the maturation of the organic matter in the shales. The shales have high quartz contents and significant amounts of other minerals such as plagioclase feldspar (albite), mica and carbonates (calcite and dolomite), and can respond favorably to hydraulic fracturing. The reserve estimate indicates that the study area could have a potential for about 23 trillion cubic feet of unproved technically recoverable natural gas reserves.

[pt] Reservatórios de shale gas/shale oil possuem elevado grau de anisotropia devido à presença de fraturas naturais (NFs) e também da orientação dos estratos. Com isso as fraturas induzidas hidraulicamente (HFs) interagem com as NFs e geram uma rede de fraturas com morfologia complexa. A existência de NFs modifica o campo de tensões no folhelho e influencia diretamente o comportamento geomecânico das HFs durante a operação de fraturamento, gerando ramificações na fratura dominante e contribuindo para a formação da rede complexa de fraturas. A construção de uma rede de fraturas aumenta significativamente a condutividade da formação, pois conecta fraturas e poros que anteriormente encontravam-se isolados, incrementando assim o índice de produtividade dos poços e proporcionando maior viabilidade econômica nos projetos em reservatórios de shale gas/oil. Este trabalho apresenta uma análise de sensibilidade da influência do espaçamento entre fraturamentos na construção da rede de fraturas complexas gerada em shales, visando entender como este parâmetro modifica o volume de reservatório estimulado e a distribuição de propante na rede de fraturas, de maneira a evitar problemas nesta fase do projeto e assim, manter a sustentação da rede economicamente viável. A revisao de literatura contempla os principais trabalhos publicados sobre este tema e os modelos não-convencionais de fraturas (UFM) usados para a modelagem da rede de fraturas complexas. A análise de sensibilidade será realizada por meio do software MShale, que usa um método estocástico de rede de fraturas discretas (DFN) e resolve numericamente as equações de equilíbrio e da poroelasticidade para shales, em termos de tensões efetivas, além das equações de conservação de massa, momento linear e energia com dissipação viscosa para escoamento lento (creeping flow). Para a análise, os demais parâmetros que influenciam na contrução da rede serão mantidos constantes e somente o espaçamento entre fraturamentos sofrerá variação. / [en] Shale gas/shale oil reservoirs have a high degree of anisotropy due to the presence of natural fractures (NFs) and also the orientation of beddings. Thus, hydraulically induced fractures (HFs) interact with NFs and generate a network of fractures with complex morphology. The existence of NFs modifies the stress field in the shale and directly influences the geomechanical behavior of the HFs during the fracturing operation, generating branches in the dominant fracture and contributing to the complex network of fractures. The construction of a network of fractures significantly increases the conductivity of the formation, as it connects previously isolated fractures and pores, thus increasing the productivity index of the wells and providing greater economic viability in the shale gas/oil reservoir designs. This work presents a sensitivity analysis of the influence of fracturing spacing in the construction of the network of complex fractures generated in shales, aiming to understand how this parameter modifies the volume of stimulated reservoir and the distribution of propant in the network of fractures, in order to avoid problems in this step of the design and thus, maintain the economical viability of the network. The literature review includes the main published works on this subject and the non-conventional fracture models (UFM) used to model the network of complex fractures. Sensitivity analysis will be performed using the MShale software, which uses a stochastic of the discrete fracture network (DFN) method and numerically solves the equilibrium equations and poroelasticity for shales in terms of effective stresses, in addition to mass conservation equations, linear momentum and energy with viscous dissipation for creeping flow. For the analysis, the other parameters that influence the construction of the network will be kept constant and only the spacing between fracturings will suffer variation.

The Eagle Ford play in south Texas is currently one of the hottest plays in the United States. In 2012, the average Eagle Ford rig count (269 rigs) was 15% of the total US rig count. Assessment of the oil and gas resources and their associated uncertainties in the early stages is critical for optimal development. The objectives of my research were to develop a probabilistic methodology that can reliably quantify the reserves and resources uncertainties in unconventional oil and gas plays, and to assess Eagle Ford shale oil and gas reserves, contingent resources, and prospective resources. I first developed a Bayesian methodology to generate probabilistic decline curves using Markov Chain Monte Carlo (MCMC) that can quantify the reserves and resources uncertainties in unconventional oil and gas plays. I then divided the Eagle Ford play from the Sligo Shelf Margin to the San Macros Arch into 8 different production regions based on fluid type, performance and geology. I used a combination of the Duong model switching to the Arps model with b = 0.3 at the minimum decline rate to model the linear flow to boundary-dominated flow behavior often observed in shale plays. Cumulative production after 20 years predicted from Monte Carlo simulation combined with reservoir simulation was used as prior information in the Bayesian decline-curve methodology. Probabilistic type decline curves for oil and gas were then generated for all production regions. The wells were aggregated probabilistically within each production region and arithmetically between production regions. The total oil reserves and resources range from a P_(90) of 5.3 to P_(10) of 28.7 billion barrels of oil (BBO), with a P_(50) of 11.7 BBO; the total gas reserves and resources range from a P_(90) of 53.4 to P_(10) of 313.5 trillion cubic feet (TCF), with a P_(50) of 121.7 TCF. These reserves and resources estimates are much higher than the U.S. Energy Information Administration’s 2011 recoverable resource estimates of 3.35 BBO and 21 TCF. The results of this study provide a critical update on the reserves and resources estimates and their associated uncertainties for the Eagle Ford shale formation of South Texas.

Production of oil and gas from shale is often described as a revolution to energyproduction in North America. Since the beginning of this century the shale oilproduction has increased from practically zero to currently supply almost half of theU.S. oil production. This development is made possible by the technology ofhorizontal drilling and hydraulic fracturing. Since the production has not been ongoingfor that long, production data is still fairly limited in length and there are still largeuncertainties in many parameters, for instance production decline, lifespan, drainagearea, geographical extent and future technological development. More research isneeded to be able to estimate future production and resources with more certainty. At the moment shale oil is extracted only in North America but around the worldinvestigations are starting to assess if the conditions are suitable from shale oilextraction elsewhere. The global technically recoverable resource has been estimatedto 345 Gb, 10% of all global technically recoverable resources. Health andenvironmental aspects of shale oil and gas production have not yet been investigatedthoroughly and there is a risk that these parameters may slow down or limit thespreading of shale development. This report aims to examine production patterns of shale oil wells by applying declinecurve analysis. This analysis comprises of analyzing historical production data toinvestigate how the future production may develop. The area of the study is the EagleFord shale play in Texas, U.S. The goal is to fit decline curves to production data andthen use them for making estimates of future production in the Eagle Ford. The production in the shale oil wells included in the study reach their peak already within a few months after production starts. After this point, production is declining.After one year, production has decreased by 75% and after two years the productionis 87% of the peak production. The hyperbolic decline curve has a good fit toproduction data and in many cases the curve is close to harmonic. It is too early todetermine whether the alternative decline curve that is tested, the scaling declinecurve, has a better fit in the long term. The report also investigates how the density of the petroleum affects the declinecurve. The result is that lighter products decline faster than heavier. A sensitivity analysis is performed to illustrate how different parameters affect thefuture production development. In addition to the wells’ decline rate, the assumptionson the maximum number of wells, the maximal production and the rate at which newwells are added affect the ultimately recoverable resource. These parameters all havelarge uncertainties and makes resource estimations more difficult.