Accuracy and Precision of Reservoir Fluid Characterization Tests Through Blind Round-Robin Testing

2021 ◽  
Author(s):  
Arwa Mawlod ◽  
Afzal Memon ◽  
John Nighswander
Keyword(s):  
Molar Mass ◽  
Sensitivity Study ◽  
Round Robin ◽  
Fluid Composition ◽  
Mass Measurements ◽  
Reservoir Fluid ◽  
Stock Tank ◽  
Fluid Characterization ◽  
Plus Fraction ◽  
The Impact

Abstract Objectives/Scope: Oil and gas operators use a variety of reservoir engineering workflows in addition to the reservoir, production, and surface facility simulation tools to quantify reserves and complete field development planning activities. Reservoir fluid property data and models are fundamental input to all these workflows. Thus, it is important to understand the propagation of uncertainty in these various workflows arising from laboratory fluid property measured data and corresponding model uncertainty. The first step in understanding the impact of laboratory data uncertainty was to measure it, and as result, ADNOC Onshore undertook a detailed study to assess the performance of four selected reservoir fluid laboratories. The selected laboratories were evaluated using a blind round-robin study on stock tank liquid density and molar mass measurements, reservoir fluid flashed gas and flashed liquid C30+ reservoir composition gas chromatography measurements, and Constant Mass Expansion (CME) Pressure-Volume-Temperature (PVT) measurements using a variety of selected reservoir and pure components test fluids. Upon completion of the analytical study and establishing a range of measurement uncertainty, a sensitivity analysis study was completed using an equation of state (EoS) model to study the impact of reservoir fluid composition and molecular weight measurement uncertainty on EoS model predictions. Methods, Procedures, Process: A blind round test was designed and administered to assess the performance of the four laboratories. Strict confidentiality was maintained to conceal the identity of samples through blind test protocols. The round-robin tests were also witnessed by the researchers. The EoS sensitivity study was completed using the Peng Robinson EoS and a commercially available software package. Results, Observations, Conclusions: The results of the fully blind reservoir fluid laboratory tests along with the statistical analysis of uncertainties will be presented in this paper. One of the laboratories had a systemic deviation in the measured plus fraction composition on black oil reference standard samples. The plus fraction concentration is typically the largest weight percent component in black oil systems and, along with the plus fraction molar mass, plays a crucial role in establishing the mole percent overall reservoir fluid compositions. Another laboratory had systemic issues related to chromatogram component integration errors that resulted in inconsistent carbon number concentration trends for various components. All laboratories failed to produce consistent molecular weight measurements for the reference samples. Finally, one laboratory had a relative deviation for P-V measurements that were significantly outside the acceptable range. The EoS sensitivity study demonstrates that the fluid composition and stock tank oil molar mass measurements have a significant impact on EoS model predictions and hence the reservoir/production models input when all other parameters are fixed. Novel/Additive Information: To the best of our knowledge, this is the first time such an extensive and fully blind round-robin test of commercial reservoir fluid characterization laboratories has been completed and published in the open literature. The industry should greatly benefit from this first-of-its-kind blind round-robin dataset being made available to all. The study provides the basis, protocols, expectations, and recommendations for such independent round-robin testing for fluid characterization laboratories on a broader scale.

Numerical Investigation of Gravitational Compositional Grading in Hydrocarbon Reservoirs Using Centrifuge Data

2009 ◽  
Vol 12 (05) ◽  
pp. 793-802 ◽  
Author(s):  
P. David Ting ◽  
Birol Dindoruk ◽  
John Ratulowski
Keyword(s):  
Experimental Data ◽  
Phase Behavior ◽  
Rock Properties ◽  
Model Parameters ◽  
Fluid Composition ◽  
Bulk Fluid ◽  
Reservoir Fluid ◽  
Fluid Systems ◽  
Fluid Properties ◽  
The Impact

Summary Fluid properties descriptions are required for the design and implementation of petroleum production processes. Increasing numbers of deep water and subsea production systems and high-temperature/high-pressure (HTHP) reservoir fluids have elevated the importance of fluid properties in which well-count and initial rate estimates are quite crucial for development decisions. Similar to rock properties, fluid properties can vary significantly both aerially and vertically even within well-connected reservoirs. In this paper, we have studied the effects of gravitational fluid segregation using experimental data available for five live-oil and condensate systems (at pressures between 6,000 and 9,000 psi and temperatures from 68 to 200°F) considering the impact of fluid composition and phase behavior. Under isothermal conditions and in the absence of recharge, gravitational segregation will dominate. However, gravitational effects are not always significant for practical purposes. Since the predictive modeling of gravitational grading is sensitive to characterization methodology (i.e., how component properties are assigned and adjusted to match the available data and component grouping) for some reservoir-fluid systems, experimental data from a specially designed centrifuge system and analysis of such data are essential for calibration and quantification of these forces. Generally, we expect a higher degree of gravitational grading for volatile and/or near-saturated reservoir-fluid systems. Numerical studies were performed using a calibrated equation-of-state (EOS) description on the basis of fluid samples taken at selected points from each reservoir. Comparisons of measured data and calibrated model show that the EOS model qualitatively and, in many cases, quantitatively described the observed equilibrium fluid grading behavior of the fluids tested. First, equipment was calibrated using synthetic fluid systems as shown in Ratulowski et al. (2003). Then real reservoir fluids were used ranging from black oils to condensates [properties ranging from 27°API and 1,000 scf/stb gas/oil ratio (GOR) to 57°API and 27,000 scf/stb GOR]. Diagnostic plots on the basis of bulk fluid properties for reservoir fluid equilibrium grading tendencies have been constructed on the basis of interpreted results, and sensitivities to model parameters estimated. The use of centrifuge data was investigated as an additional fluid characterization tool (in addition to composition and bulk phase behavior properties) to construct more realistic reservoir fluid models for graded reservoirs (or reservoirs with high grading potential) have also been investigated.

New Downhole-Fluid-Analysis Tool for Improved Reservoir Characterization

2008 ◽  
Vol 11 (06) ◽  
pp. 1107-1116 ◽  
Author(s):  
Chengli Dong ◽  
Michael D. O'Keefe ◽  
Hani Elshahawi ◽  
Mohamed Hashem ◽  
Stephen M. Williams ◽  
...  
Keyword(s):  
Real Time ◽  
Hydrocarbon Composition ◽  
Fluid Composition ◽  
Fluid Sample ◽  
Fluid Analysis ◽  
Reservoir Fluid ◽  
Reservoir Conditions ◽  
Fluid Properties ◽  
Fluid Characterization ◽  
Compositional Grading

Summary Downhole fluid analysis (DFA) has emerged as a key technique for characterizing the distribution of reservoir-fluid properties and determining zonal connectivity across the reservoir. Information from profiling the reservoir fluids enables sealing barriers to be proved and compositional grading to be quantified; this information cannot be obtained from conventional wireline logs. The DFA technique has been based largely on optical spectroscopy, which can provide estimates of filtrate contamination, gas/oil ratio (GOR), pH of formation water, and a hydrocarbon composition in four groups: methane (C1), ethane to pentane (C2-5), hexane and heavier hydrocarbons (C6+), and carbon dioxide (CO2). For single-phase assurance, it is possible to detect gas liberation (bubblepoint) or liquid dropout (dewpoint) while pumping reservoir fluid to the wellbore, before filling a sample bottle. In this paper, a new DFA tool is introduced that substantially increases the accuracy of these measurements. The tool uses a grating spectrometer in combination with a filter-array spectrometer. The range of compositional information is extended from four groups to five groups: C1, ethane (C2), propane to pentane (C3-5), C6+, and CO2. These spectrometers, together with improved compositional algorithms, now make possible a quantitative analysis of reservoir fluid with greater accuracy and repeatability. This accuracy enables comparison of fluid properties between wells for the first time, thus extending the application of fluid profiling from a single-well to a multiwall basis. Field-based fluid characterization is now possible. In addition, a new measurement is introduced--in-situ density of reservoir fluid. Measuring this property downhole at reservoir conditions of pressure and temperature provides important advantages over surface measurements. The density sensor is combined in a package that includes the optical spectrometers and measurements of fluid resistivity, pressure, temperature, and fluorescence that all play a vital role in determining the exact nature of the reservoir fluid. Extensive tests at a pressure/volume/temperature (PVT) laboratory are presented to illustrate sensor response in a large number of live-fluid samples. These tests of known fluid compositions were conducted under pressurized and heated conditions to simulate reservoir conditions. In addition, several field examples are presented to illustrate applicability in different environments. Introduction Reservoir-fluid samples collected at the early stage of exploration and development provide vital information for reservoir evaluation and management. Reservoir-fluid properties, such as hydrocarbon composition, GOR, CO2 content, pH, density, viscosity, and PVT behavior are key inputs for surface-facility design and optimization of production strategies. Formation-tester tools have proved to be an effective way to obtain reservoir-fluid samples for PVT analysis. Conventional reservoir-fluid analysis is conducted in a PVT laboratory, and it usually takes a long time (months) before the results become available. Also, miscible contamination of a fluid sample by drilling-mud filtrate reduces the utility of the sample for subsequent fluid analyses. However, the amount of filtrate contamination can be reduced substantially by use of focused-sampling cleanup introduced recently in the next-generation wireline formation testers (O'Keefe et al. 2008). DFA tools provide results in real time and at reservoir conditions. Current DFA techniques use absorption spectroscopy of reservoir fluids in the visible-to-near-infrared (NIR) range. The formation-fluid spectra are obtained in real time, and fluid composition is derived from the spectra on the basis of C1, C2-5, C6+, and CO2; then, GOR of the fluid is estimated from the derived composition (Betancourt et al. 2004; Fujisawa et al. 2002; Dong et al. 2006; Elshahawi et al. 2004; Fujisawa et al. 2008; Mullins et al. 2001; Smits et al. 1995). Additionally, from the differences in absorption spectrum between reservoir fluid and filtrate of oil-based mud (OBM) or water-based mud (WBM), fluid-sample contamination from the drilling fluid is estimated (Mullins et al. 2000; Fadnes et al. 2001). With the DFA technique, reservoir-fluid samples are analyzed before they are taken, and the quality of fluid samples is improved substantially. The sampling process is optimized in terms of where and when to sample and how many samples to take. Reservoir-fluid characterization from fluid-profiling methods often reveals fluid compositional grading in different zones, and it also helps to identify reservoir compartmentalization (Venkataramanan et al. 2008). A next-generation tool has been developed to improve the DFA technique. This DFA tool includes new hardware that provides more-accurate and -detailed spectra, compared to the current DFA tools, and includes new methods of deriving fluid composition and GOR from optical spectroscopy. Furthermore, the new DFA tool includes a vibrating sensor for direct measurement of fluid density and, in certain environments, viscosity. The new DFA tool provides reservoir-fluid characterization that is significantly more accurate and comprehensive compared to the current DFA technology.

scholarly journals Effect of Compositional Grading On reservoir Performance

1996 ◽  
Vol 1 (1) ◽  
pp. 37
Author(s):  
M. Al-Rumhy ◽  
A. Al-Bemani ◽  
F. Boukadi
Keyword(s):  
Oil Recovery ◽  
Simulation Analysis ◽  
Fluid Composition ◽  
Fluid Viscosity ◽  
Reservoir Performance ◽  
Reservoir Fluid ◽  
Stock Tank ◽  
Fluid Properties ◽  
Secondary Oil Recovery ◽  
Compositional Grading

In reservoirs with thickness exceeding fifty meters, compositional guiding has been found to cause significant variation in performance. Main fluid properties, governing the magnitude of reservoir performance, such as density; formation volume factor and fluid viscosity experience variation due to varying fluid composition along the hydrocarbon column. These variations cause erroneous estimation of stock-tank oil in place and may infer reservoir engineers to consider inappropriate secondary oil recovery methods, for example. In the presence of gravity segregation within the oil column, heavy ends will form a heavy oil blanket in the lower part of the reservoir. Such a scenario may result in poor displacement and an earlier breakthrough when water drive is the dominant fluid flow mechanism. In this paper reservoir performance due to varying reservoir fluid composition has been examined using  reservoir simulation analysis and recommendations for better characterization of reservoir fluid sampling are outlined.

Predicting Reservoir Fluid Phase and Volumetric Behavior From Samples Contaminated With Oil-Based Mud

2002 ◽  
Vol 5 (03) ◽  
pp. 197-205 ◽  
Author(s):  
F. Gozalpour ◽  
A. Danesh ◽  
D.-H. Tehrani ◽  
A.C. Todd ◽  
B. Tohidi
Keyword(s):  
Phase Equilibrium ◽  
Phase Behavior ◽  
Volatile Oil ◽  
Fluid Composition ◽  
Fluid Analysis ◽  
Reservoir Fluid ◽  
Different Types ◽  
The Impact ◽  
Mud Filtrate ◽  
Equilibrium Calculations

Summary The impact of sample contamination with oil-based mud filtrate on phase behavior and properties of different types of reservoir fluids, including gas condensate and volatile oil, has been investigated. Two simple methods are used to determine the uncontaminated fluid composition from contaminated samples. The capability of the methods is demonstrated against highly contaminated samples. An equation-of-state (EOS)-based method also has been developed to predict the phase and volumetric properties of the retrieved composition. The method determines the required parameters of the EOS for the uncontaminated fluid using the developed phase-behavior models from contaminated-sample data. The method has been examined against experimental data of different types of reservoir fluids with successful results. Introduction Accurate reservoir fluid composition and properties are essential for reservoir management and development. Reliable reservoir fluid samples are therefore required; however, major challenges can render the fluid analysis limited in value. The reservoir fluid samples for pressure/volume/temperature (PVT) tests can be collected by bottomhole and/or surface sampling techniques as appropriate. During the drilling process, owing to overbalance pressure in the mud column, mud filtrate invades the formation. If an oil-based mud is used in the drilling, it can cause major difficulties in collecting high-quality formation fluid samples. Because the filtrate of oil-based drilling mud is miscible with the formation fluid, it could significantly alter the composition and phase behavior of the reservoir fluid. Even the presence of a small amount of oil-based filtrate in the collected sample could significantly affect the PVT properties of the formation fluid. Oil-based mud is used widely in the petroleum industry. Contamination with oil-based mud filtrate could affect reservoir fluid properties such as saturation pressure, formation volume factor, gas/liquid ratio, and stock-tank liquid density. Because collecting a reservoir fluid sample is expensive, and accurate reservoir fluid properties are needed in reservoir development, it is highly desirable to determine accurate composition and phase behavior for the reservoir fluid from contaminated samples. This study investigates the impact of sample contamination with oil-based mud filtrates on composition and phase behavior properties of different types of reservoir fluids, including volatile oil and gas condensate samples. The samples were purposely contaminated with a known amount of oil-based mud filtrates in the laboratory. The methods developed in this study were then applied to determine the original composition of the reservoir fluid from contaminated samples. The phase behavior of the contaminated samples was also investigated by performing constant composition expansion (CCE) tests at reservoir and surface conditions. The measured experimental data were used to tune EOSs by adjusting their parameters. The determined parameters of EOS tuned to the contaminated samples were used to calculate the parameters of EOS for the uncontaminated sample. EOS EOSs are used extensively to simulate the volumetric behavior and phase equilibrium of petroleum reservoir fluids. Among different types of EOSs, cubic EOSs have enjoyed considerable success in modeling because they are simple and give reliable results in phase equilibrium calculations. Two EOSs, the Valderrama1 modification of the Patel-Teja (VPT) EOS and a modified Peng-Robinson2 (mPR) EOS, were used in this study to perform phase equilibrium calculations. All binary interaction parameters (BIP) in the mixing rule were set to zero, and the temperature dependency of the attractive term was used as the tuning parameter to fit the measured data.3 Extended compositional analyses (up to C20+) of fluids were used in phase equilibrium calculations. The required critical properties of petroleum fractions to calculate parameters of EOS were determined by perturbation expansion correlations.4 The required boiling-point temperatures were calculated from the Riazi- Daubert5 correlation using the molecular weight and specific gravity of petroleum fractions. The Lee-Kesler6 correlation was used to calculate the accentric factor of compounds. Contaminated Reservoir Fluids Hydrocarbon-based fluids (natural or synthetic oils) are generally used in oil-based drilling muds. Because these fluids are soluble in the reservoir fluid, they can render the fluid analysis limited in value. Determination of the original fluid composition from the analysis of a contaminated sample is feasible, but isolating the properties of the reservoir fluid free from contamination is not easily accomplished. Despite the recent improvements in sampling reservoir fluids,7,8 obtaining a contamination-free formation fluid is a major challenge, particularly in openhole wells. Therefore, modeling techniques are required, along with the laboratory studies, to determine the composition and PVT properties of the uncontaminated fluid. We have demonstrated, as have other investigators,9,10 that an exponential relationship exists between the concentration of components in the C8+ portion of real reservoir fluids and the corresponding molecular weights. For example, if the molar concentration of single carbon number groups is plotted against their molecular weights, it will give a straight line on a semilogarithmic scale. Based on this feature of natural fluids, two methods have been developed in this study to retrieve the original composition of reservoir fluid from contaminated samples. The composition of the C8+ portion of contaminated sample is plotted against molecular weight on a semilogarithmic scale. The plotted data will show a departure from the line over the range affected by the contaminants (see Fig. 1). The concentrations of the contaminants are then skimmed from the semilog straight line, presumed to be valid for the uncontaminated reservoir fluid. The fitted line is used to determine the composition of the uncontaminated fluid. The above method, referred to as the Skimming method, gives a reliable composition of the uncontaminated fluid if the contaminant comprises a limited hydrocarbon range. MacMillan et al.11 developed a similar method. They fitted a gamma distribution function to the composition of the C7+ portion of contaminated oil samples, excluding the composition of contaminants from the datafitting procedure.

scholarly journals Modeling Bacterial Regrowth and Trihalomethane Formation in Water Distribution Systems

Water ◽  
2021 ◽  
Vol 13 (4) ◽  
pp. 463
Author(s):  
Gopinathan R. Abhijith ◽  
Leonid Kadinski ◽  
Avi Ostfeld
Keyword(s):  
Distribution Systems ◽  
Water Distribution ◽  
Mechanistic Model ◽  
Water Distribution Systems ◽  
Sensitivity Study ◽  
Operating Conditions ◽  
Growth Rate Constant ◽  
Model Parameters ◽  
Bacterial Regrowth ◽  
The Impact

The formation of bacterial regrowth and disinfection by-products is ubiquitous in chlorinated water distribution systems (WDSs) operated with organic loads. A generic, easy-to-use mechanistic model describing the fundamental processes governing the interrelationship between chlorine, total organic carbon (TOC), and bacteria to analyze the spatiotemporal water quality variations in WDSs was developed using EPANET-MSX. The representation of multispecies reactions was simplified to minimize the interdependent model parameters. The physicochemical/biological processes that cannot be experimentally determined were neglected. The effects of source water characteristics and water residence time on controlling bacterial regrowth and Trihalomethane (THM) formation in two well-tested systems under chlorinated and non-chlorinated conditions were analyzed by applying the model. The results established that a 100% increase in the free chlorine concentration and a 50% reduction in the TOC at the source effectuated a 5.87 log scale decrement in the bacteriological activity at the expense of a 60% increase in THM formation. The sensitivity study showed the impact of the operating conditions and the network characteristics in determining parameter sensitivities to model outputs. The maximum specific growth rate constant for bulk phase bacteria was found to be the most sensitive parameter to the predicted bacterial regrowth.

scholarly journals A model sensitivity study of the impact of clouds on satellite detection and retrieval of volcanic ash

2015 ◽  
Vol 8 (5) ◽  
pp. 1935-1949 ◽  
Author(s):  
A. Kylling ◽  
N. Kristiansen ◽  
A. Stohl ◽  
R. Buras-Schnell ◽  
C. Emde ◽  
...  
Keyword(s):  
Radiative Transfer ◽  
Liquid Water ◽  
Volcanic Ash ◽  
Spectral Band ◽  
Sensitivity Study ◽  
Transfer Model ◽  
Mass Loading ◽  
Ice Clouds ◽  
Medium Range Weather Forecast ◽  
The Impact

Abstract. Volcanic ash is commonly observed by infrared detectors on board Earth-orbiting satellites. In the presence of ice and/or liquid-water clouds, the detected volcanic ash signature may be altered. In this paper the sensitivity of detection and retrieval of volcanic ash to the presence of ice and liquid-water clouds was quantified by simulating synthetic equivalents to satellite infrared images with a 3-D radiative transfer model. The sensitivity study was made for the two recent eruptions of Eyjafjallajökull (2010) and Grímsvötn (2011) using realistic water and ice clouds and volcanic ash clouds. The water and ice clouds were taken from European Centre for Medium-Range Weather Forecast (ECMWF) analysis data and the volcanic ash cloud fields from simulations by the Lagrangian particle dispersion model FLEXPART. The radiative transfer simulations were made both with and without ice and liquid-water clouds for the geometry and channels of the Spinning Enhanced Visible and Infrared Imager (SEVIRI). The synthetic SEVIRI images were used as input to standard reverse absorption ash detection and retrieval methods. Ice and liquid-water clouds were on average found to reduce the number of detected ash-affected pixels by 6–12%. However, the effect was highly variable and for individual scenes up to 40% of pixels with mass loading >0.2 g m−2 could not be detected due to the presence of water and ice clouds. For coincident pixels, i.e. pixels where ash was both present in the FLEXPART (hereafter referred to as "Flexpart") simulation and detected by the algorithm, the presence of clouds overall increased the retrieved mean mass loading for the Eyjafjallajökull (2010) eruption by about 13%, while for the Grímsvötn (2011) eruption ash-mass loadings the effect was a 4% decrease of the retrieved ash-mass loading. However, larger differences were seen between scenes (standard deviations of ±30 and ±20% for Eyjafjallajökull and Grímsvötn, respectively) and even larger ones within scenes. The impact of ice and liquid-water clouds on the detection and retrieval of volcanic ash, implies that to fully appreciate the location and amount of ash, hyperspectral and spectral band measurements by satellite instruments should be combined with ash dispersion modelling.

Flow Assurance and Thermodynamic Challenges of operating CO2 Pipelines for variations in terrains and environments

2021 ◽  
Author(s):  
Terence George Wood ◽  
Scott Campbell ◽  
Nathan Smith
Keyword(s):  
Process Equipment ◽  
Fluid Composition ◽  
Ambient Conditions ◽  
Operating Modes ◽  
Hydrocarbon Reservoir ◽  
Compositional Approach ◽  
Operational Life ◽  
Geographical Distances ◽  
Fluid Behaviour ◽  
The Impact

Abstract The requirement for capturing and storing Carbon Dioxide will continue to grow in the next decade and a fundamental part of this is being able to transport the fluid over large geographical distances in numerous terrains and environments. The evolving nature of the fluid supply and the storage characteristics ensure the operation of the pipeline remains a challenge throughout its operational life. This paper will examine the impact of changes in the fluid composition, storage locations, ambient conditions and the various operating modes the pipeline will see throughout the lifecycle, highlight the technical design and operational challenges and finally give guidance on future developments. The thermodynamic behaviour of CO2 with and without impurities will be demonstrated utilising the fluid characterisation software, MultiflashTM. The fluid behaviour and hydraulic performance will be calculated over the expected operational envelope of the pipeline throughout field life, highlighting the benefits and constraints of using the single component module in OLGATM whilst comparing against a compositional approach when dealing with impurities. The paper will demonstrate through two case studies of varying nature including geographical environment, storage location (aquifer vs. abandoned hydrocarbon reservoir) and ambient conditions, the following issues: The impact of the storage type on the pipeline operations and how this will evolve with time; The environmental conditions and the impact these have on selection of process equipment and operational procedures (i.e. shutdown); and The impact the CO2 composition has on the design of the CO2 pipeline, and The paper will conclude with a set of guidelines for undertaking design analysis of CO2 pipelines for variations in fluid composition, storage locations and ambient conditions as well as some key operational strategies. This paper utilises the current state of the art tools and how these evolving tools are making this technically challenging area more mainstream.

Local Mesh Refinement for Correlation of FEA Estimated Plastic Strain to Tests in Areas of High Plastic Strain

2018 ◽  
Author(s):  
Katharine Liu ◽  
Emma Xiao ◽  
Gregory Westwater ◽  
Christopher R. Johnson ◽  
J. Adin Mann
Keyword(s):  
Plastic Strain ◽  
Mesh Refinement ◽  
Sensitivity Study ◽  
Linear Elastic ◽  
Mesh Sensitivity ◽  
Local Mesh Refinement ◽  
Order Of Magnitude ◽  
High Plastic Strain ◽  
Stabilization Technique ◽  
The Impact

The total strain, elastic plus plastic, was measured with strain gages on valve bodies with internal pressure that caused surface yielding. The correlation of the simulated maximum principal strain was compared to strain gage data. A mesh sensitivity study shows that in regions of large plastic strain, mesh elements are required that are an order of magnitude smaller than what is used for linear elastic stress analysis for the same structure. A local mesh refinement was adequate to resolve the local high strain values. Both the location and magnitude of the maximum strain changed with a local mesh refinement. The local mesh refinement requirement was consistent over several structures that were tested. The test and simulation work will be presented along with the mesh sensitivity study. Some results on using an energy stabilization technique to aid convergence will be presented in terms of the impact on the predicted plastic strain.

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