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Dallas, TX, United States

DeGolyer and MacNaughton is a petroleum consulting company based in Dallas, Texas, with offices in Houston, Moscow, Calgary*, and Algiers.DeGolyer and MacNaughton was founded in 1936 by Everette Lee DeGolyer and Lewis MacNaughton. In 2004, it acquired Calgary-based Outtrim Szabo Associates forming its office in Canada as a subsidiary company. Wikipedia.

Luo Z.,DeGolyer and MacNaughton | Bryant S.,University of Calgary
Energy Procedia | Year: 2014

In large-scale CO2 sequestration project the formation temperature decreases as huge amounts of relatively cool CO2 are injected. Injection induced fractures from injectors are facilitated as the critical pressure in the formation for fracturing is reduced by considerable thermo-elastic stress, which is proportional to the temperature difference between CO2 and reservoir . In this study, we analyze injection induced fracture growth and its impact on CO2 plume migration by a semi-analytical quasi-steady state model in the case that injection induced fractures are permitted by regulators. By parametric analysis with the model, geological properties and operating conditions are investigated to show their sensitivity on fracture growth and CO2 migration. This work provides analytical tools, which enable fast and simple screening of appropriate storage sites and of injection strategy, to predict fracturing and CO2 migration to avoid potential risks. © 2014 The Authors Published by Elsevier Ltd. Source

Jenkins C.D.,DeGolyer and MacNaughton
EAGE Shale Workshop 2010: Shale - Resource and Challenge | Year: 2010

In order to characterize reservoir and hydraulic fracture properties using well performance data in shale gas reservoirs, it is essential to apply an appropriate workflow and advanced modeling techniques. The workflow should begin with a review of the well data followed by the use of analytical methods to identify different types of well behavior and to form hypotheses about the various production mechanisms at work. Numerical modeling can then proceed, first with scoping models and then with detailed numerical models to conduct production forecasting and completion optimization sensitivities. A useful tool for this detailed modeling is finite-element simulation which places a large number of closely-spaced nodes near the hydraulic fractures. This extremely fine-scale gridding captures high-resolution pressure transients that dominate well behavior during the first few years of production. The results of this work provide key insights into reservoir and fracture properties, and can be used to optimize production forecasts, well placements, lateral lengths, and completion techniques. Source

Jenkins C.,DeGolyer and MacNaughton
Society of Petroleum Engineers - Canadian Unconventional Resources and International Petroleum Conference 2010 | Year: 2010

In order to more accurately characterize reservoir and hydraulic fracture properties from well performance, a workflow has been developed that effectively integrates variable quality data from a variety of sources. This workflow applies analytical techniques designed specifically for shale gas wells followed by as-needed numerical modeling. The analytical techniques can be applied to multiple wells through time to: a) identify groupings of like-performing wells, b) detect wells with anomalous behaviors, c) develop hypotheses about production mechanisms, and d) choose specific wells for more detailed analysis and numerical modeling. Numerical modeling provides the functionality needed for complex mechanism forensics, performance forecasting, and completion optimization studies. Conventional numerical models typically use finite-difference grids, but these are neither sufficiently complex nor sufficiently flexible for shale gas reservoirs. For this reason, a finite-element modeling technology has been applied that places a large number of closely-spaced nodes near hydraulic fractures, "where all the action takes place" in the early life of a well. The finite-element technique also allows complex fracture geometries to be modeled. This workflow, incorporating analytical and numerical solutions, has been applied to multiple shale gas projects, including industry consortia in the Haynesville (US) and Montney (Canada) shales and individual operator projects in the Woodford (US), Horn River (Canada), and Marcellus (US) shales. Through the application of these techniques, fracture and reservoir properties have been characterized and uncertainty associated with forecasted well performance has been reduced. This work has profound implications for quantifying gas reserves, understanding those factors responsible for variations in well performance, and for optimizing well spacing, lateral lengths, and completion techniques. Copyright 2010, Society of Petroleum Engineers. Source

Zambrano L.,University of Calgary | Ramirez J.F.,University of Calgary | Ramirez J.F.,DeGolyer and MacNaughton | Pedersen P.K.,University of Calgary | Aguilera R.,University of Calgary
SPE Reservoir Evaluation and Engineering | Year: 2016

The Monteith Formation is an important tight gas reservoir in the Deep Basin, Alberta, and consists of a progradational succession of shallow marine sediments, nonmarine carbonaceous and coaly, coastal plain facies, and coarse-grained fluvial deposits, from base to top, respectively. This study is based on multiscale description and characterization techniques with cores and drill cuttings, including multimethods laboratory measurements of key reservoir parameters such as porosity and permeability. A second stage of the study involves the use of laboratory measurements obtained from cores and drill cuttings and their integration with well logs to construct a numerical 3D model of the study area. The 3D model is used to history match gas production, and forecast performance of new wells in those areas where the geologic model indicates potential for gas production. The ultimate goal is to provide a better understanding of the distribution of reservoir properties in the study area for developing drilling prospects and their production potential in areas where reliable data are scarce. The reservoir-modeling stage is carried out by implementing a recently developed methodology that integrates a variable shape distribution (VSD) model, capable of capturing different reservoir properties throughout the whole scale spectrum without any data truncation. Truncation is the excuse generally used for eliminating information that does not fit a given distribution. The claim is that the data are of poor quality, something that is not true in many cases. This new methodology eliminates the need for truncation, and introduces an extension of the VSD approach for reservoir-simulation purposes that reduces uncertainty in the generation of drilling prospects. Core analysis shows that the Monteith A member is composed of complex fluvial-dominated deposits with better rock quality than the shallow marine sandstones of the Monteith C member. This is most likely because of larger pore-throat apertures that range between 0.5 and 1 lm, and a relatively higher proportion of preserved intergranular pore space within these coarser-grained framework grains. Furthermore, the best production performance is from wells that are producing from the Monteith A. Variability of production rates also seems to be controlled by the presence of natural fractures. It is anticipated that the resulting 3D reservoir model will allow improving field-development strategies for this and other similar unconventional gas reservoirs in the Deep Basin of Alberta and elsewhere. © Copyright 2016 Society of Petroleum Engineers. Source

Ramirez J.F.,University of Calgary | Ramirez J.F.,DeGolyer and MacNaughton | Aguilera R.,University of Calgary
SPE Reservoir Evaluation and Engineering | Year: 2016

Production of shale and tight oil is the cornerstone of the United States race for energy independence. According to the US Energy Information Administration, approximately 90% of the oil-production growth comes from six tight-oil plays. The Eagle Ford is one of these plays, and it accounts for 33% of the oil-production growth with a contribution of 1.3 million B/D. This is outstanding. However, oil recoveries as a percentage of the original oil in place (OOIP) are extremely low. This must be improved. A geological challenge in the Eagle Ford shale is the understanding of unconventional fluids distribution over geologic time: Shallower in the structure, there is black oil; deeper and to the south; condensate appears; and at the bottom, dry gas can be found. Differences in burial depth, temperature, and vitrinite reflectance are used to explain this unique distribution. A similar fluid distribution occurs in other unconventional reservoirs (e.g., Duvernay shale in Canada). The low oil recovery and the unusual distribution of fluids led to the key objective of this paper-to identify the main factors that control fluid migration (caused by buoyancy of gas in oil) from one zone to another through geologic time. This was performed by constructing a conceptual cross-sectional compositional simulation model with northwest/southeast orientation that allowed the study of fluid migration, fluid distribution, and fluid contacts throughout 1 million years while maintaining computational time within reasonable limits. The controlling parameters studied were porosity, permeability, pore-throat aperture (rp35), and spacing between natural fractures. Results show that fluids in the matrix remained with approximately the same original distribution (i.e., approximately the same dry-gas/condensate contact and approximately the same condensate/oil contact). These fluids are the target of an ongoing research project with the ultimate goal of improving oil recovery from tight reservoirs by means of enhanced oil recovery (EOR) (Fragoso et al. 2015). There is, however, some gas migration through natural fractures to the top of the structure. This migration is interpreted in this study to be responsible for higher initial gas production in some oil wells in the top of the structure. Some operators indicate, however, that rapid gas/oil-ratio increases in the updip oil region are the result of low reservoir pressures and the rapid onset of two-phase flow. It would probably take geochemical evidence to support this conclusion. © Copyright 2016 Society of Petroleum Engineers. Source

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