No description available.

According to the 2011 Energy Information Agency (EIA) global assessment, Mexico ranks 4th in shale gas resources. The Eagle Ford shale is the formation with the greatest expectation in Mexico given the success it has had in the US and its liquids-rich zone. Accurate estimation of the resource size and future production, as well as the uncertainties associated with them, is critical for the decision-making process of developing shale oil and gas resources. The complexity of the shale reservoirs and high variability in its properties generate large uncertainties in the long-term production and recovery factors of these plays. Another source of uncertainty is the limited production history. Given all these uncertainties, a probabilistic decline-curve analysis approach was chosen for this study, given that it is relatively simple, it enables performing a play-wide assessment with available production data and, more importantly, it quantifies the uncertainty in the resource size. Analog areas in the US Eagle Ford shale were defined based on available geologic information in both the US and Mexico. The Duong model coupled with a Markov Chain Monte Carlo (MCMC) methodology was used to analyze and forecast production of wells located in the previously defined analog sectors in the US Eagle Ford shale. By combining the results of individual-well analyses, a type curve and estimated ultimate recovery (EUR) distribution for each of the defined analog sectors was obtained. These distributions were combined with well-spacing assumptions and sector areas to generate the prospective-resources estimates. Similar probabilistic decline-curve-analysis methodology was used to estimate the reserves and contingent resources of existing wells. As of March 2013, the total prospective resources (P90-P50-P10) for the Eagle Ford shale in Mexico (MX-EFS) are estimated to be 527-1,139-7,268 MMSTB of oil and 17- 37-217 TSCF of gas. To my knowledge, this is the first oil estimate published for this formation in Mexico. The most attractive sectors based on total estimated resources as well as individual-well type curves are located in the southeast of the Burgos Basin and east-west of the Sabinas basin. Because there has been very little development to date, estimates for reserves and contingent resources are much lower than those for prospective resources. Estimated reserves associated with existing wells and corresponding offset well locations are 18,375-34,722-59,667 MMSCF for gas and zero for oil. Estimated contingent resources are 14-64-228 MSTB of oil and 8,526-13,327- 25,983MMSCF of gas. The results of this work should provide a more reliable assessment of the size and uncertainties of the resources in the Mexican Eagle Ford shale than previous estimates obtained with less objective methodologies.

Thesis (M.S.)--Auburn University, 2007. / Abstract. Vita. Includes bibliographic references (ℓ. 207-218)

Thesis (Ph. D.)--University of Wisconsin--Madison, 1946. / Typescript. Vita. eContent provider-neutral record in process. Description based on print version record. Includes bibliographical references.

Thesis (M.S.)--West Virginia University, 2009. / Title from document title page. Document formatted into pages; contains xi, 68 p. : ill. (some col.), col. maps. Includes abstract. Includes bibliographical references (p. 66-68).

Orientador: Antonio Carlos Luz Lisboa / Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Quimica / Made available in DSpace on 2018-08-05T00:22:31Z (GMT). No. of bitstreams: 1 Almeida_AndreRicardoFelklde_M.pdf: 3790165 bytes, checksum: 4cd0eda3c0035bb3f544cbdb6c95a8e8 (MD5) Previous issue date: 2005 / Resumo: Por ser a maior reserva de combustível fóssil existente na terra o xisto vem sendo objeto de várias pesquisas. Estas pesquisas se referem a modelos cinéticos e a modelos de transferência de calor de massa no processo de pirólise de xisto. Porém, sendo o xisto uma rocha sedimentar formada por componentes orgânicos complexos (principalmente o queogênio) distribuído numa matriz mineral, existem várias discordâncias entre estes trabalhos no que se refere ao mecanismo de desvolatilizaçã. A maioria destes trabalhos pressupõe que o processo de desvolatilização do xisto ocorre de forma homogênea ou segundo o modelo do núcleo não reagido. Sendo o mecanismo de desvolatilização de suma importância para o projeto de retortas para pirolisar o xisto, o presente trabalho tem por objetivo investigar experimentalmente qual o mecanismo de desvolatilização do xisto. Para tal, partículas de xisto com formato paralelepipédico, com dimensões de 0,06 m x 0,04 m x 0,03 m, foram pirolisadas e desvolatilizadas parcialmente em um forno mufla com atmosfera de nitrogênio. A seguir a partícula foi seccionada e amostras do seu interior foram submetidas à analise termogravimétrica (TGA). Durante os experimentos de pirólise no forno mufla as temperaturas do centro e da superfície das partículas forma registradas ...Observação: O resumo, na íntegra, poderá ser visualizado no texto completo da tese digital / Abstract: Oil shale, the largest reserve of fossil fuels in the word, has been the subject of many investigations. These investigations has involved studies related to kinetic models, as well as heat and mass transfer regardein the pyrolysis reaction. Due to oil shale complex structure ¿ a sedimentary rock comprising organic matter, named kerogen, scattered in a inert matrix ¿ the studies have diverged about the pyrolysis or devolatilization mechanism. Most researches indicate the mechanism follows the shirinking core model (SCM) or the homogeneous model. As the objective of the present work was to study this mechanisnm. In order to do that, paallelepidedic oil shale particles, measuring 0,06m x 0,04m x 0,03m, were partially pyrolized in a muffle furnace under inert atmosphere. Subsequently, the particle was severes to expose an inner cross section. Samples were collected and submitted to thermogravimetric analysis (TGA) to obtain the organic matter profile within the particle. During each pyrolysis run, the temperatures at the particle center and surface were recorded. The results indicated that the devolatilizations mechanism do not follow the shrinking core model. It follows more likely the homogenous model, in which the different onganic matter content throughout the partially pyrolyzed shale particle is acconunted for by the temperature gradient within the partiele ...Note: The complete abstract is available with the full electronic digital thesis or dissertations / Mestrado / Engenharia de Processos / Mestre em Engenharia Química

Shale gas reservoirs have become a major source of energy in recent years. Developments in hydraulic fracturing technology have made these reservoirs more accessible and productive. Apart from other dissimilarities from conventional gas reservoirs, one major difference is that a considerable amount of gas produced from these reservoirs comes from desorption. Ignoring a major component of production, such as desorption, could result in significant errors in analysis of these wells. Therefore it is important to understand the adsorption phenomenon and to include its effect in order to avoid erroneous analysis. The objective of this work was to imbed the adsorbed gas in the techniques used previously for the analysis of tight gas reservoirs. Most of the desorption from shale gas reservoirs takes place in later time when there is considerable depletion of free gas and the well is undergoing boundary dominated flow (BDF). For that matter BDF methods, to estimate original gas in place (OGIP), that are presented in previous literature are reviewed to include adsorbed gas in them. More over end of the transient time data can also be used to estimate OGIP. Kings modified z* and Bumb and McKee’s adsorption compressibility factor for adsorbed gas are used in this work to include adsorption in the BDF and end of transient time methods. Employing a mass balance, including adsorbed gas, and the productivity index equation for BDF, a procedure is presented to analyze the decline trend when adsorbed gas is included. This procedure was programmed in EXCEL VBA named as shale gas PSS with adsorption (SGPA). SGPA is used for field data analysis to show the contribution of adsorbed gas during the life of the well and to apply the BDF methods to estimate OGIP with and without adsorbed gas. The estimated OGIP’s were than used to forecast future performance of wells with and without adsorption. OGIP estimation methods when applied on field data from selected wells showed that inclusion of adsorbed gas resulted in approximately 30 percent increase in OGIP estimates and 17 percent decrease in recovery factor (RF) estimates. This work also demonstrates that including adsorbed gas results in approximately 5percent less stimulated reservoir volume estimate.

The Black Shale Basin of West Texas covers an area in excess of 21,000 square miles and includes the region from Terrell and Pecos Counties eastward to Menard and Kimble Counties. It extends from Real, Edwards, and Val Verde northward beyond Glasscock and Upton Counties. This basin includes such local basins as the "Midland Basin," and "Val Verde Basin," of Frank E. Lewis, the "Sheffield Channel," and the "Kerr Basin." Reasons are given for the belief that the black shale sediments in this basin were derived from rocks south of this area. The shale ranges in age from Bend (lower Pennsylvanian) through Clear Fork (middle Permian). The shale of the Midland Basin has been divided into three distinct zones. Pre-Cretaceous erosion has removed the offlapping Permian shale in the extreme southern portion of the area leaving Pennsylvanian directly beneath the Trinity. The problem of stratigraphy is complicated by gradation and lack of diagnostic fossils. There is a great divergence of opinion as to correlative formational units derived from a study of the well cuttings. / text

Frequently a discrepancy is found between the stimulated shale volume (SSV) estimated from production data and the SSV expected from injected water and proppant volume. One possible explanation is the presence of a fracture network, often termed fracture complexity, that may have been opened or reopened during the hydraulic fracturing operation. The main objective of this work is to investigate the role of fracture complexity in resolving the apparent SSV discrepancy and to illustrate whether the presence of reopened natural fracture network can be observed in pressure and production data of shale gas wells producing from two shale formations with different well and reservoir properties. Homogeneous, dual porosity and triple porosity models are investigated. Sensitivity runs based on typical parameters of the Barnett and the Horn River shale are performed. Then the field data from the two shales are matched. Homogeneous models for the two shale formations indicate effective infinite conductivity fractures in the Barnett well and only moderate conductivity fractures in the Horn River shale. Dual porosity models can support effectively infinite conductivity fractures in both shale formations. Dual porosity models indicate that the behavior of the Barnett and Horn River shale formations are different. Even though both shales exhibit apparent bilinear flow behavior the flow behaviors during this trend are different. Evidence of this difference comes from comparing the storativity ratio observed in each case to the storativity ratio estimated from injected fluid volumes during hydraulic fracturing. In the Barnett shale case similar storativity ratios suggest fracture complexity can account for the dual porosity behavior. In the Horn River case, the model based storativity ratio is too large to represent only fluids from hydraulic fracturing and suggests presence of existing shale formation microfractures.

No description available.