bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Four Thermal Recovery Methods for Bitumen Extraction
Authors: Mukhametshina A. , Morrow A. W. , Aleksandrov D. , Hascakir B. 
Published: June 2014

Abstract
Around 70% of the world's bitumen resources are deposited in Western Alberta. Surface mining is applicable only to 20% of the total reserves, and in-situ cold production can only be effective to recover the 5% of the initial bitumen in place. This low extraction yield mainly stems from the high viscosities of bitumen, which can be reduced dramatically with the application of thermal recovery. However, economically viable and technically feasible bitumen extraction with thermal methods is challenging. There are also a range of adverse environmental issues associated with thermal methods. As conventional resources decline and since conventional recovery methods are insufficient to extract unconventional reserves effectively, it is necessary to address these issues associated with thermal recovery methods.
In this study, we evaluated the recovery characteristics of a Canadian bitumen (8.8 °API-53,000 cp, at 21 °C) with four thermal recovery methods. A two-dimensional physical model was used to evaluate the performances of Steam-Assisted Gravity Drainage (SAGD) and Hot Water Injection (HWI) with SAGD well configuration. Steam Flooding (SF) and In-Situ Combustion (ISC) experiments were performed with two separate one-dimensional experimental set-ups.
Experimental conditions were maintained identical at reservoir average conditions. The effluent gas composition, temperature profiles, oil recovery, behavior of fluid (oil, water, steam, and gas) front movements, and the level of oil upgrading were discussed by considering the environmental and economic constrains of the processes. Furthermore, core samples were extracted from the model to evaluate and visualize the sweep efficiency. Experimental findings reveal that ISC yielded the highest (∼90 wt %) and HWI the lowest (∼33 wt %) oil recoveries. In terms of environmental footprints, SF produced the highest amount of gases per barrel oil production, and HWI resulted in the lowest gas production. Among HWI, SAGD, and SF, energy consumption was the greatest in SAGD and the worst sweep efficiency was obtained with SF. Our results recommend a hybrid utilization of thermal recovery methods, specifically HWI with ISC for the extraction of this bitumen. HWI prepares the reservoir for ISC by aiding to increase reservoir temperature and reducing the reservoir heterogeneities with hot water distribution.
Characterization of Encapsulated Oil as an Additive to Water-Based Drilling Fluids: Operational Improvements in Lubricity, Drag, and ROP
Authors: Schuh F. J. , Coragliotti A. , DiCicco C. D. , Nagatani R. A. , Rea A. , Carlton T. , Johnson P. , Noble R. 
Published: June 2014

Abstract

Description of Proposed Paper
As the drilling industry moves towards extended-reach wells in more challenging formations, the need to identify operational solutions (e.g., drilling fluids/lubricity additives) to reduce friction, torque, and drag has become more important. Additionally, as the industry looks to maximize the use of water-based drilling fluids (to benefit from lower drilling fluid costs and improved environmental profile), the need to find novel additives that can improve lubricity has become more pressing. However, current methodologies for reducing downhole friction in horizontal wells generally involve reactive addition of lubricant products that are broadly acting, that may adversely affect the rheology of the fluid system, or that may dissipate or degrade over time. To address the need for new additives, a novel biotechnology method for encapsulating oil in polysaccharide-based polymers has been developed that selectively delivers high pressure lubricants at areas of high shear, pressure, and friction (e.g., between the drill string and formation or casing and also between drill bit and formation).

Application
Due to the protection afforded by encapsulation, this targeted friction inhibitor can be proactively added to water-based drilling fluid systems, where it circulates through the system until conditions are met to break the capsule and release lubricant. Observations in laboratory and field testing suggest potential operational improvements in running casing, reduction of torque/drag, reduction of bit balling, and faster Rate of Penetration (ROP) from targeted lubrication.

Results, Observations and Conclusions
Our characterization of encapsulated oil has shown the ability to reduce the coefficient of friction by over 80% in water-based mud formulations in the laboratory. In field-scale testing at the Catoosa Testing Facility, we have observed reductions in drag of up to 50%, reductions in torque of up to 45%, and up to 20% improvement in Rate of Penetration (ROP) in horizontal drilling after addition of encapsulated oil to a water-based polymer mud system. These results were substantially improved relative to observed results in an exploratory field well, in which ROP increased by up to 216% after addition of encapsulated oil in a saturated sodium chloride drilling fluid system.

Significance of Subject Matter
Our field testing and characterization in the laboratory and field have demonstrated the utility of adding encapsulated oil to a water-based mud-system to drill horizontal wells to improve the operational efficiency of drilling.
The Toxicity Characterization and Detoxification of two Formaldehyde-Releasing Oilfield Microbial Control Additives
Authors: Fallahtafti Shirin 
Published: June 2014

Abstract
An increased awareness of the environmental impact and operational cost associated with freshwater usage in energy production has shifted industry interest towards replacing freshwater sources with produced water in oilfield stimulation applications. Produced water often contains high concentrations of bacterial assemblages, which can cause operational challenges such as corrosion, slime formation, and souring. Microbial control agents are subsequently necessary to manage the poor water quality of most produced water sources. However, such chemicals are highly reactive and relatively unspecific, making their toxicity both a performance metric and an ecological, human health, and disposal concern. Given the advantageous biological activity of microbial control agents, controlled detoxification following use is a pertinent factor in responsible hazard management. Formaldehyde-releasing agents are a widely used category of microbial control additives which slowly and continuously release small amounts of formaldehyde, a toxic environmental pollutant and known human carcinogen. This research evaluated the acute (short-term) aquatic toxicity of two liquid formaldehyde-releasing microbial control additives, identified necessary parameters for their detoxification, and measured the resulting change in their toxicity over time, using a light-based acute toxicity test. The additives investigated were a tetrakis(hydroxymethyl)phosphonium sulfate (THPS)-based product (approximately 75% active by weight), and a 1,3-dimethylol-5,5-dimethylhydantoin (DMDMH)-based product (approximately 70% active by weight). Laboratory results suggest that the THPS-based additive was three times more toxic than the DMDMH-based additive on a percent volume basis, and pH was an important factor in THPS toxicity. Data were consistent with a maximum sixfold decrease in DMDMH toxicity for a 0.05% (v/v) solution following eight days of aeration at 0.15±0.05 liters per minute (LPM) (corresponding to a total of 172.8 LAir/mLSample), and more than a twelvefold decrease in THPS toxicity for a 0.05% (v/v) solution following a pH increase and eight days of aeration at 0.15±0.05 LPM (corresponding to a total of 172.8 LAir/mLSample). Aeration alone decreased the toxicity of DMDMH over the course of eight days, while a combination of aeration and pH increase were necessary to decrease the toxicity of THPS over the same time period. This work presents a proof of concept for a relatively simple and cost effective detoxification of the evaluated additives and highlights the key parameters for this process.
A Critical Review of Hydraulic Fracturing Fluids over the Last Decade
Authors: Al-Muntasheri Ghaithan A. 
Published: June 2014

Abstract
Hydraulic fracturing is a well-established process to enhance productivity of oil and gas wells. Fluids are used in fracture initiation and the subsequent proppant and/or sand transport. Several chemistries exist for these fluids. This paper summarizes the published literature over the last decade (90+ technical articles) and captures the advances in the design of water-based fracturing fluids. Despite their old introduction, guar-based polymers are still being used in fracturing operations for wells at temperatures less than 300°F (148.9°C). In order to minimize the damage associated with this class of polymers, the industry attempted several approaches. These include the use of lower polymer concentration in formulating these fluids. Another approach was to alter the crosslinker chemistry so that one can generate higher viscosity values with lower polymer loadings. Moreover, the industry shifted towards the use of cleaner guar-based polymers. The reason is the fact that commercial guar contains a minimum of 5 wt.% residues that cause damage to proppant packs. With fracturing deeper wells in hotter reservoirs, the need arose for a new class of thermally stable polymers. Thus, the industry shifted towards polyacrylamide-based polymers. These synthetic polymers offer sufficient viscosity at temperatures up to 232°C (450°F). Examples included 2-acrylamido-2-methylpropanesulfonic acid (AMPS) and copolymers of partially hydrolyzed polyacrylamide (PHPA)-AMPS-vinyl phosphonate (PAV). To address the challenge of high pressure pumping requirements on the surface, high density brines have been used to increase the hydrostatic pressure by 30%. On the breakers chemistry, new breakers were introduced. These breakers decrosslink the gel by reacting with the crosslinker. In order to minimize the environmental impact of using massive amounts of fresh water and to minimize costs associated with treating produced water, the use of produced water in hydraulic fracturing treatments has been reported. In addition, the paper captures the advancements in the use of slickwater where use is made of drag reducing agents (PAM-based polymers) to minimize friction. The paper highlights the first use of breakers that were introduced to improve the cleanup of these drag reducers. For foamed fluids, new viscoelastic surfactants (VES) that are compatible with CO2 are discussed. The paper also sheds light on the use of emerging technologies such as nanotechnology in the design of new efficient hydraulic fracturing fluids. For example, nanolatex silica was used to reduce the concentration of boron used in conventional crosslinkers. Another advancement in nanotechnology was the use of 20 nm silica particles suspended in guar gels. The paper provides a thorough review on all of these advancements.
Evaluation of CO2-EOR and Storage Potential in Mature Oil Reservoirs
Authors: Saini Dayanand , Jimenez Ivan 
Published: June 2014

Abstract
The selection of candidate reservoirs for future CO2 enhanced oil recovery (EOR) and storage projects greatly relies on methodical screening and detailed site specific evaluations. Once suitable reservoirs are identified in an initial screening for further evaluation, CO2-Prophet screening model could be used for a better understanding of proposed EOR project performance and site specific incidental CO2 storage prior to launching detailed and time consuming reservoir simulation studies. This paper reports on the use of publicly available geological and reservoir data and CO2-Prophet model for performing such analysis for two deep mature light oil reservoirs situated in the Kern County, California. In initial screening, these reservoirs have already been found amenable for CO2-EOR and storage.
Often, calibration of CO2-prophet model is either overlooked or just performed for achieving a material balance for oil and water phases. In addition to commonly used calibration step that involves a match for field water cut versus cumulative oil recovery history since waterflooding to achieve material balance for oil and water phases, we propose the use of an average gas-oil ratio match plot for obtaining a reasonable material balance for produced gas phase. A reservoir specific calibration of CO2-Prophet model for obtaining material balance for all three phases is aimed to increase confidence in future performance prediction results. We describe calibration procedure of the CO2-Prophet model in detail and use appropriately calibrated models for predicting CO2-EOR performance and incidental CO2 storage potentials in the reservoirs which have been already found ameable for CO2-EOR and storage in initial screening.
Beyond EOR based volumetric predications or other simple estimations made in initial screening of candidate reservoirs, appropriately calibrated CO2-Prophet model can provide more robust and reservoir specific estimates of CO2-EOR and incidental CO2 storage potential for a candidate reservoir. Such approach can be used for making initial business decisions such as selection of propective pilot sites or field acquisition while avoiding the need of detailed reservoir simulation studies. The results presented in the study clearly demonstrate that deep and mature light oil reservoirs of Kern County, California have potential for large scale (injection of more than 1 million metric tons of CO2 per year) CO2-EOR and storage projects.
An Integral Type Curve for Managing Cyclic Steam Processes
Authors: Gentile Lauren , Ershaghi Iraj 
Published: June 2014

Abstract
In this study we suggest a procedure to examine cumulative cycle response vs. cumulative injection in cyclic steam stimulation (CSS) application. This integral process is aimed at capturing the residual effect of prior steam cycles as well as de-saturation and re-saturation of pore volume in the vicinity of the wellbore. The proposed plotting method provides a diagnostic tool for examining the impact of operational factors and can serve as a lumped parameter predictive tool given the actual responses of some prior cycles.
Calibrated cumulative plots are first developed from the early cycles and predictions are shown for successive cycles. The proposed approach is providing a workable graphical tool that can capture both the improved or deteriorating condition exhibited on cycle responses. It can then help in the design of optimal planning of injected steam for successive cycles.
Sensitivities of Fractured Horizontal Wells in Shale Gas Plays to Technical and Economic Parameters
Authors: Carratu J. C. , Ozkan S. , Ozkan E. 
Published: June 2014

Abstract
Sensitivities of fractured horizontal wells in shale-gas plays to selected technical and economic parameters are discussed. An example data set is used and the low, base, and high values of the sensitivity parameters are considered. Technical performances are analyzed by using an analytical trilinear-flow model and the results are presented in the form of productivity indices, tornado charts, and the derivative of productivity index with respect to the sensitivity parameters. The sensitivities of economic indicators, such as net present value, internal rate of return, and the break-even prices are determined through a discounted cash flow model. The results indicate that the fractured horizontal well performances in shale-gas plays are relatively insensitive to natural fracture permeability and moderately sensitive to the distance between hydraulic fractures. Similarly, the hydraulic fracture permeability and half-length appear to have moderate influence on productivity. The permeability of the shale matrix and the density of the natural fractures, however, have the largest influence on productivity. For favorable project economics, optimal design of well construction and stimulation is important; however, the sensitivity of project economics to well construction and stimulation treatments is not high enough to convert a poor performer to a good one. It is essential to have good reservoir qualities to begin with for optimum well completion and stimulation design to lead to favorable economics.
Green Chemistry versus Full Chemical Disclosure and the Surrounding Industry Struggles and Perceptions
Authors: Sharp M. E. , Goudie D. R. 
Published: June 2014

Abstract
Given the social and political climates surrounding the oil and natural gas industry in North America, and more specifically hydraulic fracturing, the health, safety and education of the public and employees of operating companies is paramount. The two most common approaches being used to achieve this are using "Greener" chemistries and Full Chemical Disclosure. This paper investigates the characteristics of these two approaches, the differences between them, and the issues facing each.
One approach to protecting the health and safety of the public is by applying environmentally responsible processes, materials and equipment, also known as being "Green". Additionally the industry is striving to be as transparent as possible with public, state and federal agencies. Herein lies the tension between these two approaches: Full Chemical Disclosure is not the same as using Green chemistries. Green chemistries are being developed across the industry and contain vast amounts of intellectual property (IP) and proprietary knowledge. In order to protect the IP of these chemistries, not all of these will be available for full disclosure. This presents a major challenge in communicating with the public, which is demanding complete transparency based on the right to know what is being injected into oil and gas formations, usually far below potable water zones.
There is no universal industry definition of Green. Much of the meaning associated with the term is in the eye of the beholder. Compounding the issue, there are multiple state and federal regulations that outline what full disclosure entails. There are now 25 U.S. states that require some form of disclosure of chemicals used in hydraulic fracturing operations, up from only six states in 2011, very few of which have the same set of criteria.
This paper contains information that compares and contrasts the two approaches that are generally accepted in the industry: Green and full disclosure. It also covers state and federal regulations and some of the issues that surround them. In order for everyone to move forward on a united front, a committee of industry, state, and federal members should be formed to develop an accepted definition of Green.
Production Analysis of a Niobrara Field Using Intelligent Top-Down Modeling
Authors: Haghighat S. Alireza , Mohaghegh Shahab D. , Gholami Vida , Moreno David 
Published: June 2014

Abstract
Unconventional hydrocarbon resources are going to play an important role in the US energy strategy. Conventional tools and techniques that are used for analysis of unconventional resources include decline curve analysis, type curve matching and sometimes (in the case of prolific assets) reservoir simulation. These methods have not been completely successful due to the fact that fluid flow in unconventional reservoirs does not follow the same physical principles that supports mentioned analytical and numerical methods. Application of an innovative technology, Top-Down Modeling (TDM), is proposed for the analyses of unconventional resources. This technology is completely data-driven, incorporating field measurements (drilling data, well logs, cores, well tests, production history, etc.) to build comprehensive full field reservoir models.
In this study, a Top-Down Model (TDM) was developed for a field in Weld County, Colorado, producing from Niobrara. The TDM was built using data from more than 145 wells. Well logs, production history, well design parameters and dynamic production constrains are the main data attributes that were used to perform data driven analysis. The workflow for Top-Down Modeling included generating a high-level geological model followed by reservoir delineation based on regional productivity, reserve and recovery estimation, field wide pattern recognition (based on fuzzy set theory), Key Performance Indicator (KPI) analysis (which estimates the degree of influence of each parameter on the field production), and finally history matching the production data from individual wells and production forecasting. The results of production analysis by Top-Down Modeling can provide insightful guidelines for better planning and decision making.
Simulation Study of CO2 Huff-n-Puff Process in Bakken Tight Oil Reservoirs
Authors: Yu Wei , Lashgari HamidReza , Sepehrnoori Kamy 
Published: June 2014

Abstract
Advancements in horizontal drilling with hydraulic fracturing have enabled commercial oil production from Bakken tight oil reservoirs. However, the primary recovery factor remains very low (less than 15%), resulting in the high volume of oil remaining in place. Hence, it is extremely important to investigate the application of enhanced oil recovery methods. Carbon dioxide (CO2) injection as a huff-n-puff process is a preferred approach to improve oil recovery in tight reservoirs. In this work, we present the effect of CO2 molecular diffusion and performed a series of sensitivity studies to quantify the impacts of reservoir properties such as permeability and fracture properties such as fracture half-length, fracture conductivity, number of fractures, and operation parameters such as CO2 injection rate, injection time, soaking time, number of cycle of CO2 huff-n-puff and CO2 diffusivity on the CO2 huff-n-puff process for enhanced oil recovery in the Bakken Formation.
A numerical model was built using the typical reservoir and fracture properties from Middle Bakken to simulate CO2 huff-n-puff process. In this process, we consider CO2 molecular diffusion term to swell oil in matrix since Darcy velocity is negligible due to low permeability. The numerical model was validated with field production data from a horizontal well in Middle Bakken. Based on the history matching results, the relative permeability curves such as water-oil relative permeability and liquid-gas relative permeability, are obtained. Furthermore, the wettability for the Middle Bakken is found to be weak water wet. Simulation results show that the most important parameter is CO2 injection rate, followed by CO2 injection time, number of cycle, CO2 diffusivity. The other parameters such as fracture conductivity, CO2 soaking time, permeability and fracture half-length are less sensitive based on the range investigated in this study. The range for the incremental oil recovery factor at 30 years of production is obtained as 2.5% - 9.4%. This work can provide fundamental understanding of the key parameters controlling the CO2 huff-n-puff process for enhanced oil recovery in the Bakken Formation.