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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


Rondon J.,DeGolyer and MacNaughton | Barrufet M.A.,Texas A&M University | Falcone G.,Texas A&M University | Falcone G.,Clausthal University of Technology
Flow Measurement and Instrumentation | Year: 2012

This paper presents the performance evaluation of a novel sensor designed to measure the in situ viscosity of a fluid flowing at downhole conditions. The device provides a mechanism to allow the passage of solid particles (i.e. sand) and has a self-cleaning ability should any build-up of these particles restrict the flowing area. The sensor was assembled in a closed flow loop to prevent measurement error due to partial vaporization of the samples at higher temperatures, and it was tested and calibrated with mixtures of glycerin and water. Differential pressures, flow rates and temperatures were acquired and used to determine the viscosity of two crude oils (and mixtures of those) with viscosities ranging from 0.001 to 0.03 Pa.s (1 to 30 cp ) and temperatures from 37.8 to 71.1°C (100 to 160°F). Flow rates were controlled to maintain linearity in the differential pressure response to ensure a laminar flow regime. Viscosity measurements were validated with independent measurements using a Brookfield viscometer and the agreement was within 2%. Using data from this sensor, new viscosity mixing rules were developed to allow determination of mixture compositions from viscosity measurements or mixture viscosities for given compositions. This paper also presents a generalized mathematical model to describe the performance of the sensor with Newtonian and non-Newtonian fluids. The model characterizes the response of the sensor as a function of the parameters from a power-law model rheological description and the geometry of the device. The experimental data suggest the validity of this model for predicting the sensor response under realistic operating conditions. The model can be used to calculate optimum dimensions to fabricate a device for customized applications. Potential applications include the estimation of diluent to be added to a more viscous fluid to achieve a target viscosity reduction, fluid identification from wireline formation testers, smart well fluid monitoring, enhanced mud logging, and fracture fluid characterization. © 2011 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

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