bluuebunny/crossref_metadata_2025_split huggingface dataset:
Next-Generation Boron-Crosslinked Fracturing Fluids: Breaking the Lower Limits on Polymer Loadings
Authors: Holtsclaw Jeremy , Montenegro-Galindo G. Rocio , Chopade Prashant 
Published: September 2015

Abstract
Hydraulic fracturing is a robust stimulation technique that has been employed for more than 60 years to help increase the recovery rate of hydrocarbons from reservoirs. Hydraulic fracturing fluids are key components of the process. Significant efforts have been made to refine the fluids and advance new technology to help improve the economics, efficiency, and safety of the systems. Specifically, the pursuit of fluids that provide reliable and consistent performance while using lower concentrations of polymer, usually guar or a guar derivative, has been a recurrent point of emphasis in fracturing fluid advancement. There are many advantages of using lower polymer concentrations, including lower costs, improved logistics, and introducing less polymer with its associated residues into the fracture, among others.
This paper presents a new fracturing fluid that combines a next-generation boron crosslinker with a new hydroxypropyl guar (HPG) to be crosslinked with 40 to 60% less polymer than used in conventional borate-crosslinked fluids. For this fluid, HPG loadings in the range of 8 to 12 lbm/1,000 gal were used to produce boron-crosslinked stimulation fluids stable up to 200°F. Fluid viscosity testing showed stable fracturing fluids with controlled breaking profiles at temperatures up to 180°F. Dynamic proppant suspension testing indicated that the new fracturing fluid exhibited proppant transport equal to or better than conventional borate fluids. Regained permeability testing using Berea sandstone cores exceeded 75% at 160°F, 85% at 180°F, and 95% at 200°F. Additionally, excellent fluid cleanup was measured by retained proppant pack conductivity with 2 lbm/ft2 20/40-mesh lightweight ceramic proppant.
This new boron-crosslinked fluid retains the “rehealable” property and flexibility of conventional borate-crosslinked fluids; however, the polymer is crosslinked at or near the minimum concentration at which the polymer chains can entangle (and are capable of crosslinking), which is an improvement compared to conventional borate-fluids. This concentration is known as the critical overlap concentration, c*, of the polymer. The use of the new crosslinking technology coupled with the new HPG allows for a two-fold advantage in terms of residue reduction. The derivatized polymer requires additional processing, yielding a cleaner polymer with less residue, and the lower polymer dosage results in a further reduction of residue compared to conventional fluids.
Material-Balance Analysis of Gas Reservoirs with Diverse Drive Mechanisms
Authors: Kabir C. S. , Parekh B. , Mustafa M. A. 
Published: September 2015

Abstract
Material-balance (MB) analysis for in-place volume estimation in gas reservoirs has been in practice for decades. Nonlinear responses from geopressure reservoirs with or without aquifer influx present special interpretation challenges. One of the main challenges of in-place volume estimates involves the estimation of average-reservoir pressure with production. To that end, modern pressure sensors installed at bottomhole and/or surface largely help establish a given well's dynamic performance by way of rate-transient analysis.
This paper explores the applicability and limitations of the standard analytical tools in volumetric, geopressure, and waterdrive systems for a diverse array of fluids, from dry gas to near-critical gas/condensate. The systematic approach presented in this paper attempts to increase accuracy in results by ensuring consistency in solutions from multiple methods used to first assess the average-reservoir pressure from production performance data, followed by in-place volume estimation. In this context, we examined analytical tools, such as the pav/z vs. cumulative gas production (Gp) plot, and cumulative reservoir voidage vs. cumulative total expansion plot. Both pot aquifer and unsteady-state Carter-Tracy aquifer models were considered to account for water influx. Besides the use of Cole and drive indices plots, two diagnostic log-log plots are introduced involving total expansivity and change in average-reservoir pressure. In addition, we sought solution objectivity by introducing a diagnostic tool in the Walsh and Yildiz-McEwen MB plots. Both MB methods involve plotting of cumulative reservoir voidage (F) vs. cumulative total expansion (Et), whereas the diagnostic tool consists of plotting F/Et vs. Et on the same graph.
Initially, synthetic data helped us understand the overall system behavior and instilled confidence in the solutions obtained for various combinations of drive mechanisms. Statistical design of experiments prompted us to explore independent variables, such as aquifer-to-hydrocarbon PV ratio, production rate, degree of overpressure, and the aquifer source. Those learnings were validated with published and new field data encompassing an array of reservoirs with various drive mechanisms and fluid type.
Precision Control of Gel Formation Using Superparamagnetic Nanoparticle-Based Heating
Authors: Panthi Krishna , Mohanty Kishore K. , Huh Chun 
Published: September 2015

Abstract
A novel method of generating a polymer gel at a specified location in a subsurface formation was developed by adding superparamagnetic nanoparticles to the gel-forming polymer and heating the polymer by the nanoparticle-based hyperthermia. It blocks only the high permeability zones by highly localized gelling of the polymer employing magnetic hyperthermia heating, so that the oil in the low permeability zone can be recovered. In this paper, the gelling behavior of hydrolyzed polyacrylamide-polyethylenimine (HPAM-PEI), curdlan, methyl cellulose (MC) and hydroxypropyl methylcellulose (HPMC) was studied as a function of temperature and salinity. The effect of adding iron-oxide superparamagnetic nanoparticles (Fe3O4-NP) on gellation was also studied. The elastic and viscous moduli (G′ and G”) of curdlan suspension, and MC and HPMC solutions (with and without Fe3O4-NP) were measured which served as a quantitative measure of the gelling temperature and the gel state. For the curdlan, MC and HPMC boipolymers, the gel formation efficiency is enhanced by the presence of salts, but the presence of Fe3O4-NP does not have significant effect on gel formation.
Design and Interpretation of Transient Tests at Well's Inception
Authors: Hashmi G.M. , Kabir C.S. , Hasan A.R. 
Published: September 2015

Abstract
Operators often avoid conventional drill-stem testing (DST) in offshore environments because it is costly and its value lacks transparency. Short-duration tests may be a promising alternative to conventional DSTs for learning formation conductivity, but they should not be restricted to exploratory wells. Short-duration tests can have a profound impact in any deepwater field-development setting. Stakes are high when unfavorable productivity and injectivity indices may change the well count calculus. Tools such as formation testers provide a credible alternative, but closed-chamber tests (CCT) and/or slug tests are also helpful for situations in which large volumes of formation fluid are sampled.
Given that short-duration tests (CCT and slug) can last only a few minutes—particularly in high-conductivity reservoirs—we approached the challenge with a two-fold strategy. First, we developed a forward model to design the chamber length to ensure that we collected interpretable test data. Second, we combined the CCT and slug tests so that we could control the total test duration, particularly in high-conductivity reservoirs. The approach presented here allowed individual treatment of slug, CCT, and reverse-slug or injection test for underpressured reservoirs. Overall, the model presents a simple, yet complete approach to design and analysis of these short-term tests.
Improving Reservoir Forecasts by Understanding the Relative Impacts of Sparse Data, Reservoir Modeling Workflow and Parameter Selection, and Human Bias
Authors: Meddaugh W. Scott 
Published: September 2015

Abstract
Nandurdikar and Wallace's (2011) review of nearly 150 major capital projects showed that the industry is actually delivering only 75% of the production volumes forecast at the time of project sanction overall and those projects with identified subsurface issues delivered only 55% of the forecast volumes. In other words, the industry production forecasts are significantly optimistic. There are a variety of factors that contribute to the optimistic forecasts. The most important are areal subsurface model grid size, well location optimization workflows, sparse data bias, and “pro-project sanction” management bias. Each of these individually may contribute on the order of 10-25% or so of the observed overall forecast optimism. The impact of other factors such as stochastic model parameters (e.g. semivariogram range) and vertical upscaling are significantly less important.
Compositional Variation in SAGD
Authors: Ghasemi M. , Whitson C. H. 
Published: September 2015

Abstract
In last two decades, the steam assisted gravity drainage (SAGD) has been successfully implemented for increasing the oil recovery from bitumen reservoirs (Butler et al. 1981, Butler and Stephens 1981). This paper describes a detailed study of compositional variation in a SAGD process.
A series of 2D numerical simulations are conducted based on the generic Athabasca type reservoirs. The fluid model provided in this study developed from an extensive work on the experimental analysis and fluid characterization modeling of the Athabasca and light solvent mixtures. In the equation of state (EOS) model, Bitumen is represented by 5 pseudo-fractions ranging from light, medium and heavy to extra-heavy components. Moreover the steam based Kvalues of bitumen fraction is developed and considered in this study.
The change in the compositional variation in the edge oil-flow zone are briefly studied in this work. Based on the analysis of compositional variation, we found the presence of vaporizing-condensing mechanism (VCM) as the second order effect that helps to increase the oil recovery from a SAGD process. The viscosity profile at the edge oil-flow zone and at the residual oil behind the interface is changed when the VCM is presented. The VCM effect can be more significant if the SAGD process is examined under different type of heavy oil and bitumen samples. The effect of the oil viscosity heterogeneity (the oil viscosity increases with depth) on the performance of SAGD process is studied. The assumption of uniform oil viscosity throughout the bitumen (heavy oil) reservoir may not be representative of the measured oil viscosity in the field. The presence of the highly nonlinear vertical composition and fluid viscosity gradient in bitumen deposits is mainly due to severely biodegraded oils. Extensive degradation creates a highly nonlinear vertical viscosity variation with a large viscosity gradient at the bottom of the formation. We develop an empirical correlation which account for the nonlinearity of the viscosity variation versus depth.
The novel of this present work is introducing VCM as the second mechanism which has second order effect in increasing heavy oil recovery. Lack of accurate EOS model or inadequate number of pseudo components in the EOS model may neglect the VCM term and lead to underestimate the ultimate oil recovery e.g. ~10% of oil recovery is only gained by VCM for heavy oil with API of 14.
The Effect of Bitumen characterization and viscosity heterogeneity in a SAGD process is extensively studied in this work. Moreover, the results show that the effect of VCM in increasing oil recovery for the viscosity gradient reservoir is even more significant compared with the homogeneous viscosity. Certainly, the results of this work is essential to understand the true physics of the SAGD process in the compositional variation of the heavy oil reservoirs.
Foams with Wettability-Altering Capabilities for Oil-Wet Carbonates: A Synergistic Approach
Authors: Singh Robin , Mohanty Kishore K. 
Published: September 2015

Abstract
The goal of this work is to systematically study the effect of wettability alteration and foaming, either acting individually or synergistically, on tertiary oil recovery in oil-wet carbonate cores. Three types of anionic surfactant formulations were used: alkyl propoxy sulfate (APS), which exhibited low interfacial tension (IFT), wettability alteration (WA), and weak foaming; alpha-olefin sulfonate (AOS), which showed no WA, but good foaming; a blend of APS, AOS and a zwitterionic foam booster, which showed low IFT, WA and good foaming. First, contact angle experiments were conducted on oil-wet calcite plates to evaluate their wettability altering capabilities. Second, spontaneous imbibitions in a microchannel were performed to study the role of IFT- reduction and wettability-alteration by these formulations. Third, static foam tests were conducted to evaluate their foaming performance in bulk. Fourth, foam flow experiments were conducted in cores to evaluate potential synergism between the anionic surfactant alpha-olefin sulfonate and the zwitterionic surfactants in stabilizing foam in the absence of crude oil. Finally, oil displacement experiments were performed using a vuggy, oil-wet, dolomite core saturated with a crude oil. After secondary water floods, surfactant solutions were coinjected with methane gas at a fixed foam quality (gas volume fraction). Contact angle and spontaneous imbibition experiments showed that AOS can act as a wettability-altering surfactant in the presence of sodium carbonate, but not alone. No synergy was observed in foam stabilization via the blend of zwitterionic surfactant and alpha-olefin sulfonate solution (1:1) in a water-wet carbonate core. Oil displacement experiment in oil-wet carbonate core revealed that coinjection of wettability-altering surfactant and gas can recover significant amount of oil (33% OOIP) over waterflood. During foam flooding, with AOS as the foaming agent, only a weak foam was propagated in a carbonate core, irrespective of the core wettability. A blend of wettability-altering surfactant, AOS and zwitterionic surfactant not only altered the wettability of carbonate core from oil-wet to water-wet, but also significantly increased the foam resistance factor in the presence of crude oil.
Analysis of Drawdown Sensitivity in Shale Reservoirs Using Coupled-Geomechanics Models
Authors: Wilson Kurt 
Published: September 2015

Abstract
Productivity loss in some shale reservoirs is often attributed geomechanics-related factors, even when the exact mechanism(s) is undetermined. Overpressured reservoirs tend to experience a large increase in effective stress during depletion, which can contribute to a dramatic loss in fracture conductivity. Factors such as a low elastic modulus may also contribute to productivity loss through processes such as proppant embedment. The Haynesville Shale (Texas and Louisiana) is often cited as an example of geomechanics-related productivity loss since it is characterized by high overpressure (1.0 psi/ft in some areas) resulting in extremely high initial production rates followed by steep declines.
In this study, a simplified, single-fracture coupled model with different orientations relative to the principal stresses is used to investigate the impact of drawdown management on estimated ultimate recovery (EUR). The coupled-geomechanics reservoir simulation model was constructed using a comprehensive set of logs, rock mechanics tests and fracture conductivity measurements from a shale reservoir. In particular, various drawdown schedules (bottomhole pressure vs. time) and their effect on effective stress on the fractures were compared. Subsequently, fracture conductivity (Fc) relationships considering the maximum effective stress for each drawdown scenario were constructed and used in traditional (non-coupled) reservoir simulations to forecast gas EUR.
It was found that a managed drawdown schedule can improve EUR by up to 15%, mainly by reducing the effective stress on unpropped fracture regions. Importantly, the modelling results show that unpropped fracture “pinch points” near the wellbore may lead to very significant reduction in overall recovery. Model results showed that even proppant concentrations around 0.3 lb/ft2 maintained sufficient conductivity to not hamper well productivity in nanodarcy reservoirs. Traditional reservoir simulation approaches using compaction tables (pore pressure vs. Fc) lack the critical process of stress path dependency that governs the effective stress on the fractures and is necessary to adequately model this system.
Future experimental work should be directed at measuring unpropped fracture conductivity at high stresses and longer durations (creep) as unpropped fractures appear to be a main contributor to the observed geomechanical-related productivity loss.
A Novel Solution for Performing Real-Time Fiber Optic Temperature Measurements
Authors: Barry Alexander , Broaddus David , Ivasauskas Jonas , Johnston William 
Published: September 2015

Abstract
As Operators are increasingly seeing the value of in-well monitoring in optimizing production and reducing interventions, Operators are demanding greater accuracy, reliabilty and timeliness of well information above what is available today.
This study explores a new method of measuring temperatures in harsh downhole environments that aims to improve on some of the limitations of conventional distributed temperature sensing (DTS). Instead of using Raman backscatter signals to infer temperature, a calibrated fiber Bragg grating (FBG) array is used to measure the temperature. Bragg gratings have previously been deployed as temperature measuring devices, usually as discrete devices individually spliced in a cable. The cable design presented in this study reduces deployment costs compared to discrete Bragg gratings, and can also scale up to 1000 gratings.
Additionally, an interrogation method has been developed for measuring the wavelengths of the FBG array. Traditional swept-wavelength interrogation techniques exist to measure FBG arrays, but they are typically limited to approximately 40 gratings. Like the cable, the interrogation method scales up to 1000 gratings at 1 meter grating spacing.
Numerous system performance tests were conducted in a laboratory setting and in a simulated well environment. A prototype cable was deployed in a test well alongside a standard DTS cable. The cables were exposed to temperature cycling by circulating hot and cold fluid. Measurements produced by the two cables were recorded and analyzed.
The prototype cable test results demonstrated that the grating cable is capable of higher resolution temperature measurement than conventional DTS. The prototype interrogator will be able to perform the measurement in less than 10 seconds, a fraction of the measurement time required by conventional DTS interrogation.
Results from other tests have demonstrated the ability to perform well with long lead-in distances without losing accuracy. With this increased range, the interrogator can be located away from the wellhead and in offshore wells, above water.
Predicting Middle Bakken Well Performance with Shale Capacity
Authors: Newgord C. , Mediani M. , Ouenes A. , O'Conor P. 
Published: September 2015

Abstract
Using geologic models of porosity, brittleness, natural fracture density, total organic carbon, and saturation of oil, we develop the Shale Capacity for the Bakken reservoir. First, the 3D surface seismic data are frequency enhanced through a broadband spectral inversion. With the enhanced 3D seismic, we generate many seismic volumes of curvatures, spectral properties, post-stack acoustic impedance inversions, and pre-stack elastic inversions. A neural network is used to rank the different seismic volumes against the well log properties and then find the conditional relationships between the attributes to develop a geologic model that is predictive of the property variation away from the well control. These geologic models are combined to build the Shale Capacity model.
We quantify the Shale Capacity with the Relative Intercepted Shale Capacity (RISC) to relate the Shale Capacity to 90-day Initial Production (IP). RISC is the percentage of a wellbore's horizontal length that intercepts low to zero Shale Capacity. We determine RISC for six of the twelve horizontal wells and derive a relationship between RISC and 90-day IP. For the remaining six horizontal wells, we predict the 90-day IP using the derived correlation. Finally, we qualitatively compare the microseismic events with the Shale Capacity. Near the heel of the well where the Shale Capacity is low, the microseismic event density is lower. Similarly, where Shale Capacity is highest, the microseismic event density is higher.
Successive Substitution Augmented for Global Minimization of the Gibbs Free Energy
Authors: Eghbali Sara , Okuno Ryosuke 
Published: September 2015

Abstract
The conventional approach to multiphase flash is the sequential usage of stability and flash calculations. It is a series of local minimizations of the Gibbs free energy, in which a false solution is obtained from fugacity equations for a fixed number of phases and corrected in the subsequent stability analysis. The robustness and efficiency of multiphase flash have been important issues to be resolved for compositional reservoir simulation with complex phase behavior.
This paper presents a new algorithm to solve the correct set of equations for global minimization of the Gibbs free energy for isothermal, isobaric, multiphase flash. The Peng-Robinson equation of state with the van der Waals mixing rules is used for thermodynamic properties.
The number of equilibrium phases is part of the solution in the new algorithm, in contrast to the sequential stability/flash approach. Therefore, false solutions are not necessary for multiphase flash with the new algorithm. The advantage of the new algorithm in terms of robustness and efficiency is more pronounced for more complex phase behavior, in which multiple local minima of the Gibbs free energy are present. It is straightforward to implement the algorithm because of the simple formulation, which also allows for an arbitrary number of initial compositions.
Multi-Scale Evaluation of Nanoparticle-Stabilized CO2-in-Water Foams: From the Benchtop to the Field
Authors: Worthen Andrew , Taghavy Amir , Aroonsri Archawin , Kim Ijung , Johnston Keith , Huh Chun , Bryant Steven , DiCarlo David 
Published: September 2015

Abstract
Although EOR with CO2 is practiced domestically on large scale, the potential for advancement is enormous. The ongoing search for better solutions has motivated extensive research on alternatives to surfactant-stabilized CO2 foams for CO2 mobility control. The formation of CO2-in-water foams lowers the CO2 mobility, resulting in improvement in sweep efficiency in field tests. The crucial unmet challenge in employing CO2 foams is to maintain long-term stability of foam to achieve high sweep efficiency for the duration of the flooding process. Surfactant-stabilized foams are inherently unstable so that maintenance of the low mobility requires continuous regeneration of lamellae in the small pores of the rock. Nanoparticles can potentially be used to provide much higher foam stability and thus long-term mobility control for CO2 floods. They can act like a foaming surfactant without some of the surfactant drawbacks. Here we present a turnkey approach for using surface treated nanoparticles in reservoirs. This involves: tests for stability in brines, transportability through cores, foam generation in beadpacks and cores when co-injected with CO2, quantification of CO2 viscosity enhancement, and finally modeling of field-scale effects. In this paper, we will outline the key details of nanoparticle design for CO2 EOR.