bluuebunny/crossref_metadata_2025_split huggingface dataset:
Clinical Correlates of a Lateral‐Flow Immunoassay Oral Risk Indicator
Authors: Nwhator S.O. , Ayanbadejo P.O. , Umeizudike K.A. , Opeodu O.I. , Agbelusi G.A. , Olamijulo J.A. , Arowojolu M.O. , Sorsa T. , Babajide B.S. , Opedun D.O. 
Published: April 2013

Background: The aim of the present study is to investigate the clinical correlates of a novel lateral‐flow immunoassay with bleeding on probing (BOP), oral hygiene, and periodontal probing depth. This report offers a simple, rapid, and highly sensitive tool that addresses two issues important to periodontists: 1) detecting active periodontitis, and 2) predicting chronic periodontitis.Methods: Seventy‐six of 86 males requiring seminal fluid analysis as part of a separate study were serially recruited into the study. After basic dental and periodontal examination under natural light and with the use of the community periodontal index of treatment needs (CPITN) probe, debris and calculus indices were recorded per participant. Participants were subsequently grouped into “good,” “fair,” and “poor” oral hygiene categories based on a simplified oral hygiene index. BOP was assessed with the ball‐ended tip of the probe, and periodontitis was assessed with pocket probing as well as a lateral flow of neutrophil collagenase‐2 immunoassay, which measures levels of matrix metalloproteinase‐8.Results: Neutrophil collagenase‐2 immunoassay was 96% sensitive for poor oral hygiene, 95% sensitive for chronic periodontitis (defined as at least two sites with periodontal pockets), and 82.6% sensitive for at least two sites with BOP.Conclusion: Neutrophil collagenase‐2 immunoassay had a high sensitivity for at least two sites with BOP and two sites with periodontal pockets but a lower relationship for single‐site pockets and BOP.
Comparison of Fracture Valves vs. Plug-and-Perforation Completion in the Oil Segment of the Eagle Ford Shale: A Case Study
Authors: Stegent Neil A. , Ferguson Kip , Spencer Jon 
Published: April 2013

Summary
Which completion strategy is better: plug-and-perforation or fracture-valve? The authors of this paper will evaluate multiple completion strategies in two offset horizontal wells drilled in the oil section of the Eagle Ford shale. The first well was completed using a combination of single entry point, ball-activated fracture valves (first two-thirds of the lateral) and plug-and-perforation (P-n-P) with multiple entry points (the remainder of the lateral). The second wellbore was completed using only P-n-P with multiple entry points. Both wells were completed using comparable completion designs (hybrid fracture design, number of fracture stages, and pounds of proppant) and were cemented for annular isolation.
To determine the completion and production efficiency, microseismic mapping and oil-soluble tracer technologies were used to evaluate the differences between the completion strategies. Fracture mapping was used to compare stage “complexity,” while a hydrophobic oil tracer, which generated a pseudoproduction log of each individual stage, was used to determine the completion efficiency.
The integration of these diagnostic engineering technologies allows for interesting conclusions with respect to the fracture complexity generation from the different completion strategies, as well as the resulting production from the comparative wells. This data can provide important information regarding the difference between the two completion methods.
A Method To Perform Multiple Diagnostic Fracture Injection Tests Simultaneously in a Single Wellbore
Authors: Martin Alvin R. , Cramer David D. , Roberts Neale , Nunez Oswaldo 
Published: April 2013

Summary
This paper presents a unique process for deriving reservoir properties (i.e., minimum horizontal stress, kh/u, and reservoir pressure) in isolated reservoir layers intersected by the same vertical wellbore. It is based on simultaneously performing multiple diagnostic fracture-injection tests (DFIT) with extended multiday shut-in periods using downhole shut-in tools and bottomhole memory gauges.
A case study of 58 vertical wells completed in the Mesaverde and Dakota sandstones of the San Juan basin is used to describe and assess the above application. These intervals are gas productive, slightly to significantly subpressured, and possess a very low permeability pore network enhanced by natural fracture networks. As many as seven individual intervals per well were tested using the simultaneous process in an area spanning the entire San Juan basin. Large-scale, multistage hydraulic fracturing is necessary to establish commercial production from these intervals. The diagnostic tests were done before the large-scale fracture treatments, yet did not impede the subsequent implementation of the treatments. In the Dakota interval, the diagnostic testing results agreed well with the kh derived from post-fracture production analysis and led to a process of treatment design optimization. In the Mesaverde interval, less agreement was found between diagnostic-test and production-analysis results. Despite the lack of validation, fluid leakoff rates measured during the diagnostic testing provided insight into fracture half-length differences documented in a previous study of microseismic mapping. As part of the case study, procedural guidelines and best practices developed in the process of performing over 200 tests will be discussed.
Effect of Heterogeneity on Formation Damage in Long Horizontal Wells: An Experimental Study
Authors: Menouar Habib 
Published: April 2013

Abstract
This study is directed toward an experimental investigation of formation damage in a large heterogeneous reservoir from the Middle East. A number of experiments using real reservoir core samples at reservoir conditions of pressure and temperature have been performed. Various drilling fluid contact times with the formation and overbalance pressures have been used during these experiments. The analysis of the experimental data shows that the results have been predominantly marked by the heterogeneous nature of this reservoir. The heterogeneity of the cores affects to a great extent how the damage due to drilling fluids occurs. The results show as expected that the damage permeability increases with the contact time. As a consequence, extended drilling causes additional formation damage and higher skin. Also, without contradicting the detrimental effect of the overbalance pressure on formation damage, the experimental data show an unexpected result: Higher permeability zones of the reservoir are affected much more significantly by the drilling fluids’ damage than lower permeability zones. Similar results are obtained for invasion depth. The effect of the magnitude of the permeability on formation damage is so strong that it masks the effect of overbalance pressure on formation damage. A straight-forward conclusion is that stimulation jobs in such reservoirs should have as a primary objective to stimulate in priority the most permeable zones that have been damaged along the horizontal well instead of the low permeability zones since it pays more to regain a fraction of a very high permeability than the same or smaller fraction of a low permeability zone. Another conclusion of this study is that it is of paramount importance in formation damage to assess accurately the effect of the horizontal well effective length and its contribution to the productivity of the well compared to other parameters such as the damage permeability, the invasion depth, or the anisotropy ratio.
Simulation of Waterflooding with Coarse-Scale Dual-Porosity Representation of Highly Heterogeneous Reservoirs
Authors: Yadecuri Mohammad Evazi , Jessen Kristian 
Published: April 2013

Abstract
Upscaling of the geological model is an important component of any reservoir simulation work flow. This process introduces error due to averaging of sub-grid heterogeneity and introduces additional numerical diffusion. Upscaling errors are more severe when waterflooding is simulated in highly heterogeneous (channelized) porous media. When coarse grid blocks involve high and low permeability channels or layers, current upscaling techniques generally fail in representing the fine scale response accurately.
In this work, the effect of heterogeneity on displacement efficiency in coarse-scale modeling is studied. The pore space of the fine-scale model is ranked based on the contribution to flow. Two levels of porosity are considered and classical dual-porosity models are used for coarse-scale flow simulation. A streamline index (SI), defined as the ratio of the streamline density to the time-of-flight, is used for storage categorization: An active pore volume represents the high flow paths in the porous system while a passive pore volume is considered as source/sink that feed into the major flow pathways. Several types of cut-off values, including the span of SI and local/global cut-offs, are discussed to determine the fraction of active pore volume in each coarse grid cell.
The proposed technique is used to simulate waterflooding on two highly heterogeneous models. Displacement calculations are performed on the original fine grid and on a uniform coarse grid with global flow-based transmissibility upscaling. Simulation results from coarse single-porosity models (classical approach) and dual-porosity systems are then compared. Upscaling with dual-porosity flow modeling is demonstrated to provide for significant improvements in the accuracy of the coarse-scale simulation and arrives at a more accurate representation of the displacement performance.
Hydraulic Fracture Design Flaws- Proppant Selection
Authors: Yang Mei , Proppants Cadre , Liu Xicai , Jiao Di , Economides Michael J. 
Published: April 2013

Abstract
Proppant selection has been discussed in previous works (Yang et al, 2012), as one of the most important elements in both the physical success of a hydraulic fracture and its economic optimization. This paper continues this in-depth discussion. The study presents the statistical usage of fracture technology in major locations in Texas. The geographic analysis is consistent and valuable: similar reservoirs in the same basin call for similar treatments. The research will particularly focus on the analysis of proper proppant selection.
Texas completion and production data from the past several years, specifically on fracturing treatments in the Eagle Ford Shale and the Permian Basin, have been studied and summarized. The statistical analysis includes, but is not limited to: the fracture job size, proppant type, pay formations and the true vertical depth of the well. Important factors involved in fracture design are also represented: formation type, depth, reservoir permeability, closure stress, stress isotropy/anisotropy and post-treatment productivity.
Studies show that natural sands are the appropriate proppants for reservoirs currently under exploration in the specified plays. However, while Premium Brown Sand and Premium White Sand are the recommended proppants, this study proves that by utilizing the Unified Fracture Design model, the Net Present Values of the treatments using Premium Brown Sand are superior to those using Premium White Sand. This is established not only because of the shallower depths (and therefore less crushing) but also because Premium Brown Sand creates similar EUR at a substantially lower completion cost.
With the theory guidance of the Unified Fracture Design and extensive completion and production data analysis, this study can considerably help the oil and gas industry to effectively implement hydraulic fracturing designs.
Mechanisms Behind Low Salinity Water Flooding in Carbonate Reservoirs
Authors: Al-Shalabi Emad W. , Sepehrnoori Kamy , Delshad Mojdeh 
Published: April 2013

Abstract
The low salinity water injection method (LoSal) has become one of the important research topics in the oil industry because of its enormous possible advantages. The objective of this paper is to investigate the mechanism behind the LoSal effect on oil recovery through data matching. The UTCHEM simulator was used to match the cycles of the injected seawater and different dilutions of the latter for two recently published coreflooding experiments. The result from the history matching revealed that the wettability alteration mechanism is believed to be the main contributor to LoSal. Based on this finding, an analytical model for oil recovery predictions can be developed.
Uncertainty Assessment in Geologic Modeling and Sensitivity Analysis of Static and Dynamic Models in Umiat: A Frozen Shallow Oil Accumulation in National Petroleum Reserve of Alaska
Authors: Kohshour I. O. , Ahmadi M. , Hanks C. 
Published: April 2013

Abstract
Current high oil price and availability of new technologies allow re-evaluation of oil resources previously considered uneconomic. Umiat oil field is one such resource: a unique, shallow (275–1055 feet), low-pressure (200–400 psia) reservoir within the permafrost zone with no initial gas cap located north of the Arctic Circle, 80 miles west of Trans Alaska Pipeline System (TAPS) with an estimated 1.5 billion barrels of oil-in-place.
A static model was built based on reinterpretation of original log and core data and seismic information. A permeability anisotropy ratio of 0.45 was incorporated into the geologic model. A Monte Carlo simulation was conducted to estimate the different degrees of uncertainty in the original oil in place (OOIP) estimates. To cover the wide permeability range (0–500 md), three sand groups (rock types) were defined and assigned appropriate capillary pressure and relative permeability curves. These were included in the dynamic model along with measured PVT data and gas-oil relative permeabilities in the presence of ice to evaluate the performance of immiscible gas injection using a multilateral wagon wheel well pattern with horizontal well length of 1500 ft.
The simulation results show that with 50 years of gas injection, recovery factors for the base case (400 psia injection pressure) and a case with 600 psia injection pressure are 12% and 15%, respectively, keeping other parameters constant. Those recovery numbers reduce by 18% and 6% when producing GOR is restricted to 5,000 scf/STB and 10,000 scf/STB, respectively. The potential effect of natural fractures was modelled by considering the effect of permeability anisotropy (Kv/Kh).. Simulation results indicate that lower anisotropy ratios will reduce oil recovery, probably due to inhibition of downward gas movement.
The results obtained in this study contribute to the understanding of uncertainties in resource estimation and evaluating ranges of oil recovery in reservoir modeling. Despite limited data and lack of production history to tune the model, the results demonstrate that the proposed development plan bears a high degree of uncertainty and risk. These findings strongly encourage the operator to include in development plan strategies to reduce the risk by enhancing the quantity and quality of simulation input data.
An Efficient Reservoir Simulation Approach to Design and Optimize Unconventional Gas Production
Authors: Yu Wei , Sepehrnoori Kamy 
Published: April 2013

Abstract
Shale gas production has gained worldwide attention over the past several years. Production from shale gas reservoirs requires horizontal drilling with multiple hydraulic fracturing to obtain the most economical production. However, there are high cost and uncertainty due to many inestimable and uncertain parameters such as reservoir permeability, porosity, fracture spacing, fracture half-length, fracture conductivity, gas desorption, geomechanics and existing natural fracture. Therefore, the development of a method quantifying uncertainties and optimization of shale gas production in an efficient and practical way is clearly desirable.
In this paper, we present a user-friendly and efficient framework to obtain the optimal gas production scenario by optimizing the uncertain factors by integrating several commercial simulators, an economic model, Design of Experiment (DoE), and Response Surface Methodology (RSM) with a global optimization search engine. Specifically, we use factorial design to screen insignificant factors and find the most influential design and uncertain factors, and then employ RSM to design over those most influential factors to fit a response surface using net present value (NPV) as the objective function, and finally identify the most economical production scenario under conditions of uncertainty. Eight uncertain parameters, such as porosity, permeability, reservoir thickness, reservoir pressure, bottom hole pressure (BHP), fracture spacing, fracture half-length, and fracture conductivity with a reasonable range based on Barnett Shale information are investigated. Also, different gas prices are considered for the optimization process.
This framework is effective and efficient for hydraulic fracturing treatment design and production scheme optimization in unconventional gas reservoirs. It can contribute to providing guidance for engineers to modify the design of a hydraulic fracture treatment prior to the actual fracture treatment.
Impact of Staggered Fracture Placement on Field Development of Unconventional Gas Reservoirs: a Critical Evaluation of Overlapping SRV's
Authors: Sahai Vivek , Jackson Greg , Rai Rakesh , Lalehrokh Farshad 
Published: April 2013

Abstract
Making optimal well spacing decisions in unconventional plays is critical for commercial viability. Given the huge areal extent of these plays and low permeability, a large number of wells are needed to optimally extract the resource. The well spacing decision has to incorporate changes in geology/reservoir characteristics, completion methodology, presence of offset wells, and economic constraints. This work shows the impact of changes in reservoir properties such as permeability, completion properties as fracture spacing and completion footprint or the areal configuration of the stimulated reservoir volume (SRV) in determining optimal well spacing.
As additional development or infill wells are drilled in a section, the possibility of SRV overlap increases. When the stage/cluster placement is not staggered between the neighboring wells, the created fractures may intersect resulting in SRV destruction i.e. the fracture area accessible to the neighboring wells is less than the total fracture area created in absence of SRV overlap. With staggered placement of stages, the created fractures are at an offset and the SRV's overlap without the fractures intersecting. This results in accelerated depletion of the region between the wells by reducing the rock volume each hydraulic fracture has to drain. Thus, the neighboring wells rob some late life production potential by draining the reservoir within the study well drainage volume.
The impact of the percentage of fracture overlap, fracture spacing, and reservoir permeability on overall recovery and economic value is evaluated using synthetic models. For the scenario of SRV destruction, the NPV decreased with increasing SRV overlap. With staggered placement of fractures, there is a minor loss in NPV for less than 50% SRV overlap under the economic constraints considered. Higher than 50% overlaps may be detrimental depending on permeability and fracture spacing. Changes in cost/economic constraints also impact optimal well spacing. The presented results will assist operators in planning closer well spacing by optimizing capital expenditures and hydrocarbon recovery.
Discussion on Carbon Dioxide Minimum Miscibility Pressure Estimation: An Experimental Investigation
Authors: Menouar Habib 
Published: April 2013

Abstract
Among existing enhanced oil recovery (EOR) processes, carbon dioxide (CO2) flooding is the most widely used. The popularity of CO2 as a miscible agent is due to its characteristics, which result in excellent macroscopic and microscopic efficiencies when miscibility conditions are optimal. In most CO2 flooding studies, these conditions are related to the minimum miscibility pressure (MMP), which is the pressure above which miscibility develops and materializes in recoveries equal to or higher than 90% (Metcalfe and Yarborough,1979). Since the MMP is a quick and convenient tool for conducting screening studies for post-evaluation of miscible projects, many correlations used to estimate the MMP have been developed for various crude oils and are presented in the literature. The problem is that not all correlations reflect the necessary process parameters needed in a typical CO2 flooding project. Correlations that work for reservoirs in North America may not be suitable for reservoirs in the Middle East. This paper addresses the issues related to experimental estimation of the MMP in a large, low-permeability reservoir in the Middle East and the evaluation of correlations as a means of estimating the MMP for a given reservoir. These issues range from the experimental approach and the verification of slim tube results by core flooding experiments to the use of dead versus live oil to estimate the MMP (for instance) or the effect of impurities on the MMP of pure CO2. The use of dead oil instead of live oil to conduct both slim tube and core flooding experiments resulted in errors up to 9%. Also the effect of some gases like nitrogen, hydrogen sulfide, and methane on the MMP of pure CO2 is discussed. Among the correlations tested, only one was found to apply with a reasonable accuracy to CO2 flooding in the reservoir studied. The deviation between live and dead oil MMP slim tube experimental results is also discussed as well as the correction due to contamination of CO2 by other gases.
Injection Scheduling Design for Reduced Order Waterflood Modeling
Authors: Rezapour Amin , Tafti Tayeb Ayatollahi , Ortega Antonio , Ershaghi Iraj 
Published: April 2013

Abstract
In this paper we use the concept of experimental design from the System Identification literature and introduce a novel methodology for more accurate characterization and monitoring of waterfloods using linear models. To improve the predictability of the low order linear models they must be trained with sufficiently informative data. To achieve this goal, the input (here injection rate) must contain sufficient variations (without exceeding the technical and operational limits) so that all the relevant dynamics of the system are excited and can be seen in the output (here production rate). In sum, a successful injection scheduling design boils down to introducing predetermined variations on top of the existing injection rates. We will discuss how to design these variations, specifically their amplitude, sampling time, experiment length, frequency of variations and signal type, using priori knowledge of the reservoir dynamics and the production constraints. Our proposed methodology can be applied to currently available linear modeling techniques such as CRM, FIR, subspace models, etc. This study shows that the prediction error of a model that has been trained with a proper injection scheduling design, in a multi injector multi producer oil field, can be reduced significantly regardless of the modeling technique.
A Comprehensive Review of Alkaline-Surfactant-Polymer (ASP) Flooding
Authors: Sheng James J. 
Published: April 2013

Abstract
Alkaline-surfactant-polymer (ASP) flooding is a combination process in which alkali, surfactant and polymer are injected at the same slug. Because of the synergy of these three components, ASP is the current world-wide focus of research and field trial in chemical enhanced oil recovery.
This paper is to provide a comprehensive review of the ASP process. The reviewed topics include the following:
ASP synergy and its EOR mechanisms Screening criteria Laboratory work Numerical simulation work Summary of pilots and large-scale applications Project economics Chemicals used Water quality Salinity gradient Mobility control requirement Problems associated with ASP flooding
In addition to the comprehensive review, future developments are also discussed. Data and analyzed results presented in this review will help oil operators save research and pilot costs, and to build their confidence to execute and expedite their ASP projects.