bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mapping and Modeling Large Viscosity and Asphaltene Variations in a Reservoir Undergoing Active Biodegradation
Authors: Jackson Richard R. , Zuo Julian Y. , Agarwal Ankit , Herold Bernd , Kumar Sanjay , Santo Ilaria De , Dumont Hadrien , Ayan Cosan , Mullins Oliver C. 
Published: October 2014

Abstract
Viscosity is one of the key reservoir fluid properties. It plays a central role in well productivity and displacement efficiency and has a significant impact on completion strategies. Accurately assessing areal and vertical variations of viscosity will lead to more realistic reservoir simulation and optimal field development planning. Downhole fluid analysis (DFA) has successfully been used to measure the properties of reservoir fluids downhole in real time. DFA has excellent accuracy in measuring fluid gradients which in turn enable accurate thermodynamic modeling. Integration of DFA measurements with the thermodynamic modeling has increasingly been employed for evaluating important reservoir properties such as connectivity, fluid compositional and property gradients. The thermodynamic model is the only one that has been shown to treat gradients of heavy ends in all types of crude oils and at equilibrium and disequilibrium conditions. In addition, fluid viscosity depends on concentration of heavy ends that are associated with optical density measured by DFA. Therefore, mapping viscosity and optical density (heavy end content) is a new important application of DFA technology for use as assessment of reservoir architectures and a mutual consistency check of DFA measurements. In this case study, a very large monotonic variation of heavy end content and viscosity is measured. Several different stacked sands exhibit the same profiles. The crude oil at the top of the column exhibits an equilibrium distribution of heavy ends, SARA and viscosity, while the oil at the base of the oil column exhibits a gradient that is far larger than expected for equilibrium. The fluid properties including SARA contents, viscosity and optical density vary sharply with depth towards the base of the column. The origin of this variation is shown to be due to biodegradation. GC-chromatographs of the crude oils towards the top of the column appear to be rather unaltered, while the crude oils at the base of the column are missing all n-alkanes. A new model is developed that accounts for these observations that assumes biodegradation at the oil-water contact (OWC) coupled with diffusion of alkanes to the OWC. Diffusion is a slow process in a geologic time sense accounting for the lack of impact of biodegradation at the top of the column. An overall understanding of charging timing into this reservoir and expected rates of biodegradation are consistent with this model. The overall objective or providing a 1st-principles viscosity map in these stacked sand reservoirs is achieved by this modeling. Linking DFA with thermodynamic modeling along with precepts from petroleum systems modeling provides a compelling understanding of the reservoir.
Evaluation of Gas Adsorption in Marcellus Shale
Authors: Yu Wei , Sepehrnoori Kamy , Patzek Tadeusz W. 
Published: October 2014

Abstract
Production from shale gas reservoirs plays an important role in natural gas supply in the United States. Horizontal drilling and multi-stage hydraulic fracturing are the two key enabling technologies for the economic development of these shale gas reservoirs. It is believed that gas in shale reservoirs is mainly composed of free gas within fractures and pores and adsorbed gas in organic matter (kerogen). It is generally assumed in the literature that the monolayer Langmuir isotherm describes gas adsorption behavior in shale gas reservoirs. However, in this work, we have analyzed several experimental measurements of methane adsorption from the Marcellus Shale core samples that deviate from the Langmuir isotherm, but obey the BET (Brunauer, Emmett and Teller) isotherm. To the best of our knowledge, it is the first time to find that gas adsorption in a shale gas reservoir behaves like multilayer adsorption. Consequently, investigation of this specific gas desorption effect is important for accurate evaluation of well performance and completion effectiveness in shale gas reservoirs based on the BET isotherm. The difference in calculating original gas in place based on both isotherms is discussed. We also perform history matching with one production well from the Marcellus Shale and evaluate the contribution of gas desorption to the well's performance. History matching shows that gas adsorption obeying the BET isotherm contributes more to overall gas recovery than gas adsorption obeying Langmuir isotherm, especially early time in production. This work provides better understanding of gas desorption in shale gas reservoirs and updates our current analytical and numerical models for simulation of shale gas production.
Understanding water soluble organics in upstream production systems
Authors: Walsh John M. , Vanjo-Carnell James , Hugonin Jarid 
Published: October 2014

Abstract
A mathematical model has been developed which allows correlation and prediction of chemical and phase equilibrium of dissolved organic components in produced water. The model is applied primarily to prediction of results from the EPA-1664 method of analysis. The model provides a clear understanding of the contributions of dissolved organics, dispersed oil, and the effect of pH on the so-called Water Soluble Organics. This can be applied to understand the consequences of reducing temperature and pressure that typically occurs in the production train, and the increase in pH which typically accompanies release of CO2 into the gas phase. The model does not predict the formation or resolution of oil-in-water emulsions or dispersions. Those variables, important in the application of the model, are assumed to be measured or calculated and available for input into the present model. The model is also applied to sampling and analysis, which is an important part of processing produced water containing dissolved organics.
The main objective of the model is to help select better processes to remove dissolved organics, and to explain the role of sampling and analysis meeting discharge regulations. It is demonstrated that deep removal of dispersed organics can result in lowering of both total oil and grease and water soluble organics.
Impact of Polar Components on Crude Oil-Water interfacial Film Formation: A Mechanisms for Low-Salinity Waterflooding
Authors: Alvarado Vladimir , Garcia-Olvera Griselda , Hoyer Paulo , Lehmann Teresa E. 
Published: October 2014

Abstract
Low salinity waterflooding is a promising Improved Oil Recovery (IOR) process showing growing activity since discovery. However, incremental recovery over traditional waterflooding varies significantly. Numerous investigations have attempted to prove or disprove recovery mechanisms associated to this process. In our earlier research, we proposed that buildup of the crude oil-brine film viscoelasticity leads to suppression of trapping mechanisms during low-salinity waterflooding. We also advanced the idea that film response depends upon combined characteristics of both crude oil and water. In this paper, interfacial viscoelasticity measurements were conducted on several Wyoming crude oils as well as processed versions of the same oils with selected asphaltene content. Dual-wall ring shear rheology and pendant-drop dilational rheology were run to investigate the connection between polar content in the oil and interfacial viscoelastic response. To further investigate the connection between the interface viscoelasticity and low-salinity waterflooding mechanisms, coreflooding experiments intended to minimize geochemical events during flooding were completed using Berea sandstone. Oil recovery and pressure responses were monitored as well. Film viscoelasticity results turned out consistent with our hypothesis, namely that high content of polar components leads to high viscoelasticity of the crude oil-water interfacial film. Carefully selected coreflooding experiments were run and these results were combined with our earlier ones to unveil recovery trends. Our observations show that a good relationship exists between polar component content and interfacial viscoelasticity, and consequently with oil recovery factor, but outlying results, though favoring low-salinity waterflooding, indicate that a more complex set of interactions need to be further investigated. The conclusions of our work support an additional mechanism for low salinity waterflooding that should improve industry's ability to select candidates for this process by directing fluid-fluid characterization efforts not frequently executed at present.
Quantifying Uncertainty in Bottom-Hole Pressure Measurements Utilizing Single and Dual Gauges: A Case Study
Authors: Biswas Aakash , Al Jumah Ali , Al Joumaa Jihad , Mahdi Abdul Gaffar , Sabih Ahmed 
Published: October 2014

Abstract

Description
When the operator obtained the license to operate a super giant oil field, the available data was scarce and old, rendering a question on the adequacy and quality respectively. It was recognized that developing a field of this size would require an accelerated and extensive data gathering program. Thus, a campaign was started by the operator with a strong emphasis on reducing field level uncertainties. A part of the data gathered was static and flowing bottom-hole pressure surveys for all of the available wells on the field. Wireline and slick-line retrievable Quartz type single and dual pressure and temperature gauges were used to acquire numerous static and dynamic surveys at different points in time.
This data would be used for multiple purposes, including but not only limited to PPP (Pore pressure prediction), history matching of reservoir models, well modeling including inflow and outflow analysis and executing PSO (production system optimization) activities. The problem statement of this paper is to quantify uncertainty around the recoded pressure measurements. It was observed that the data recorded with those gauges are affected by some major external factors.
Significant improvements in accuracy of downhole pressure measurements over the past two decades have been made owing to the availability/introduction of high resolution, high precision gauges. However, due to the harsh environment of the wellbore that differs significantly from the laboratory's environment, a measurement difference can be noticed even when comparing two identical gauges (Kikani and Fair, 1997). Diagnostic plots of pressures recorded during RIH (run in hole) and POOH (pull out of hole) have been used to analyze the data sets available. The conclusion of the study comprises quantification of uncertainty of the pressure recordings and pressure survey recommendations to be implemented on the field during the operation. It has since been applied in the field with improvements made in enhancing data quality of pressure surveys.

Results/Conclusions
Seven surveys were evaluated to investigate the impact of these factors on the pressures recorded.. The study reveals that the resulting uncertainty is a cumulative effect of these factors and also a function of the sequence of operations whilst execution of the survey. By looking at the impact resulting out of these factors individually and cumulatively, it is possible to provide a deterministic uncertainty around the bottom-hole pressure measurements.
The significance of this uncertainty lies in the impact of this measurement differential on Well Productivity Indices, Pore pressure prediction, history matching and PSO identification. This impact varies but understanding of the same adds value in terms of understanding and predicting the field performance better.
Estimating Sand Production Volume in Oil and Gas Reservoir
Authors: Ray P. , Rijken M. , Cameron J. , Jones C. , El-Fayoumi A. 
Published: October 2014

Abstract
Sand control techniques are widely used in industry to prevent sand production. However these techniques significantly increase completion cost and complexity as well as can potentially impact production and field economics. Hence it is preferred not to install sand control if one can be assured that the sand volume which will be produced is manageable. However, there are no tools or workflows which can consistently and accurately predict the expected sand volume and timing over the life of the field without a large range of uncertainty.
In this study, sand production characteristics were tested in three different sandstone outcrops under varying fluid flow conditions. The test results show different sanding behavior for brine, oil, and gas flow. Samples tested with brine fail catastrophically when stress is applied which slightly exceeds the onset of sand production stress. Samples with gas flow produce small amounts of sand even when the stress significantly exceeds the onset of sand production. The test results also demonstrated the importance of drawdown pressure on sand production, where an increase in drawdown has the potential to significantly increase the sand production. Subsequently both numerical and empirical models were developed to estimate and predict sand production volume. These models have been able to model field sand production cases reasonably well
Modelling Heavy Oil Viscosity During Thermal Stimulation Using the Free Volume Theory
Authors: de la Porte J. J. , Zimmerman R. W. , Kossack C. A. 
Published: October 2014

Abstract
Large errors in oil viscosity predictions result in large production rate errors during numerical simulation, due to a first-order dependency of flow rates on viscosity. Questions that arise during thermal simulation studies of heavy oil are (1) which viscosity-temperature model could be sufficiently well based on molecular physics such that viscosity prediction, as a function of temperature, would be possible if only oil composition is available; (2) in which temperature range do viscosity predictions need to be most accurate so as to ensure most accurate recovery predictions – the high or the low end? This work will provide simulation engineers with additional tools and information to address these questions, and more accurately model production of heavy oil under thermal stimulation, by providing a viscosity model based on physical properties of molecular structure and thermodynamic behavior, and additionally, will show that the priority temperature range depends on the thermal recovery method.
The Free Volume Model (FVM), based on the concept of the ‘available free space to which a molecule can move under shear stress’, is applied in this work to three different heavy oils to calculate viscosity as a function of temperature. The model was first extended for application to extra-long chain molecules up to C64H130 by de la Porte (2012) and de la Porte and Kossack (2014); the present work will provide users with guidelines to estimate the FVT molecular characteristics for a resin-asphaltene heavy pseudo-component.
Furthermore, the range of temperatures at which accurate viscosity prediction is essential for more accurate oil recovery predictions is investigated for various recovery methods, such as cyclic steam stimulation (CSS), line-drive steam stimulation (SLD), and steam-assisted gravity-drainage (SAGD). Analytical models are used to predict the sensitivity to the viscosity error in a specific temperature range, followed by numerical simulation to confirm the findings.
This research, the first to extend the Free Volume Theory to heavy oil components, will contribute towards more accurate numerical simulation of heavy oil reservoirs.
Measuring Drilling Standardization Using Approximate String Matching
Authors: Montgomery Justin B. , O'Sullivan Francis M. 
Published: October 2014

Abstract
Standardization of drilling procedures is a key element for success in the development of unconventional oil and gas fields today. We propose approximate string matching as a data analytic technique that can be used to measure standardization across wells in a field. We describe the implementation of approximate string matching, providing details of how it can be contextualized for oil and gas drilling using operation codes, and how results can be normalized to allow for comparison between disproportionate sequences of operations. We use this technique to develop a measure for operational variability, the first objective metric for evaluating and comparing the rate and consistency of standardization across different wells, sections of wells, and rigs, informing decision-making based on the existing large streams of feedback from field operations. We provide examples of operational variability using analysis of data from about two hundred horizontal wells drilled by a single operator in a major North American unconventional field, and develop the concept of the "standardization curve" from this to demonstrate the importance of this metric in understanding learning and movement along the "learning curve" during a drilling campaign. Additionally, we outline some specific ways that these approaches can be used to automate the data-driven comparison, disaggregation, and assimilation of field learning to better manage improvement within drilling campaigns. This tool provides a foundation upon which future data analytic and machine learning techniques can build, developing learning programs for "smart" oil and gas fields that make better use of available data to enable rapid adaptation and greater overall drilling efficiency.
Evaluation of Reservoir Connectivity and Hydrocarbon Resource Size in a Deep Water Gas Field Using Multi-Well Interference Tests
Authors: Ohaeri Charles U. , Sankaran Sathish , Fernandez Juan 
Published: October 2014

Abstract
The Prosperidade field offshore Mozambique is a large deep water gas field with three main fan reservoir complexes. The field extent covers an area about fifty kilometers long and ten kilometers wide. As part of the field appraisal and development process, an extensive Drill Stem Test (DST) and Multi-Well Interference program, involving several strategically placed wells, was conducted to assist in evaluating reservoir connectivity and original gas in place. This paper presents the interference test program, First, the objectives, design methodology and criteria are discussed. Next, we present the test conduct and the methods used to retrieve interference pressure data at observation wells over time. We also discuss the challenges associated with measuring small pressure changes (&lt; 0.5 psi) in the presence of tidal effects as well as the methods we have used to handle noise and gauge pressure drift. Finally, we present the methods used to evaluate reservoir connectivity and gas in place.
In analyzing the interference pressure data, we have used both analytical methods and numerical reservoir simulation. More importantly, we have used a new material balance technique to directly calculate the original gas in place. This method uses rock and fluid data and the small changes in pressure at the observation wells. Therefore, errors and uncertainties in the input or measured data will affect the results. To account for this, the Monte Carlo simulation approach was used to provide statistics on the magnitude and range of the calculated original gas in place.
The results of the work have helped us understand the connectivity of the various fan reservoirs over several kilometers. This has been an important contribution for both field development and reserve certification
First Successful Filtercake Damage Removal Treatment Utilizing In-situ Nitrogen/Heat Generating system for Relatively Heavy Oil Wells
Authors: Al-Taq Ali A. , Al-Haji Habeeb H. , Saleem Jaffar A. 
Published: October 2014

Abstract
Nitrogen/heat generating system (N/HGS) is a thermal-chemical method comprising huge amounts of heat and nitrogen gas generated by reaction between two nitrogen-containing aqueous salts, ammonium chloride and sodium nitrate. The inherent properties of this system make it a good additive in matrix acid stimulation and clean-up treatments for heavy oil wells. The generated heat tends to reduce the oil viscosity, thus enhancing oil mobility while the generated nitrogen gas will reduce hydrostatic pressure of the oil column. Both actions will help the reservoir to better cleanup.
Lab results showed that N/HGS was effective in removing oil-based mud filtercake damage. Application of N/HGS cleanup fluid in HP/HT filter press cell was associated with an increase in pressure of more than 100 psi and in temperature of nearly 40°C. An optimized N/HGS formulation was very effective on filtercake removal; nearly 81% of flow efficiency was obtained. The N/HGS formulation contains in addition to the basic nitrogen-containing salts an organic acid, an emulsion breaker and a viscosity reducer. The organic acid, acting as a reaction catalyst in N/HGS, is also proposed to dissolve bridging material presents in filtercake, calcium carbonate.
Application of this system, for first time in Saudi Arabia, to remove oil-based filtercake damage from a sandstone horizontal well was very successful. The N/HGS components were pumped in a way to be mixed in the wellbore of the horizontal section. Coiled tubing was used to pump one component while the other component was pumped through the annulus. The reaction of N/HGS components was associated with generation of huge heat as detected by the Distributed Temperature Survey (DTS) which showed that reservoir temperature increased from 153 to more than 300°F. Following the N/HGS treatment, the dead well was able to produce naturally with a competitive production rate compared to offset wells treated with conventional clean-up fluids.
Well Spacing Optimization of Liquid Rich Shale Plays Using Reservoir Simulation
Authors: Eburi S. , Padmakar A. S. , Wilson K. , Banki R. , Wardell I. 
Published: October 2014

Abstract
In recent years, liquid rich shale plays have become the focus of many operators developing unconventional resources. After years of drilling single wells in a section to hold leases, companies are facing key field development questions – what is the appropriate well spacing and what is the right development plan for their unconventional assets? Some operators have simply used a trial and error approach while others have designed and drilled pilots to test various well spacing scenarios and multiple field development strategies following an experimental design approach. Both of these methods could take significant time before conclusive results could be observed, and these field trials often involve significant capital investment to test a few combinations with the hope of inferring the optimal solution. Another key question many operators have is how does the optimal well spacing change with fluid type or with shale play? Liquid rich shale plays like Eagle Ford, Utica and Duvernay show multiple fluid gradients. Depending on which fluids a company's acreage contains, the optimal well spacing will vary as will the development plans. Therefore, it is very important to understand the effect of fluid composition on recovery and well spacing in liquid rich shale plays. In this work, a reservoir flow simulation model is built and history matched to a synthetic liquid rich shale well production history in order to predict the estimated ultimate recovery (EUR) for various well spacing scenarios. The flow simulation model incorporates dominant shale flow and storage mechanisms including multi-phase physics. Using the calibrated simulation model, a study was performed to quantify the reduction in EUR due to well interference and sensitivities to fluid composition were conducted to understand its effects on well productivity and recovery factor. Results indicate that the outlined workflow provides a reliable tool for performance evaluation of various field development strategies and that well performance and fluid composition can have a significant impact on well spacing and field development decisions.