bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Multiscale Adaptive Local-Global Method for Modeling Flow in Stratigraphically Complex Reservoirs
Authors: Alpak Faruk O. , Pal Mayur , Lie Knut-Andreas 
Published: January 2013

Summary
A robust and efficient simulation technique is developed on the basis of the extension of the mimetic finite-difference method (MFDM) to multiscale hierarchical-hexahedral (corner-point) grids by use of the multiscale mixed finite-element method (MsMFEM). The implementation of the mimetic subgrid-discretization method is compact and generic for a large class of grids and, thereby, is suitable for discretizations of reservoir models with complex geologic architecture. Flow equations are solved on a coarse grid where basis functions with subgrid resolution account accurately for subscale variations from an underlying fine-scale geomodel. The method relies on the construction of approximate velocity spaces that are adaptive to the local properties of the differential operator. A variant of the method for computing velocity basis functions is developed that uses an adaptive local-global (ALG) algorithm to compute multiscale velocity basis functions by capturing the principal characteristics of global flow. Both local and local-global methods generate subgrid-scale velocity fields that reproduce the impact of fine-scale stratigraphic architecture. By using multiscale basis functions to discretize the flow equations on a coarse grid, one can retain the efficiency of an upscaling method, while at the same time produce detailed and conservative velocity fields on the underlying fine grid.
The accuracy and efficacy of the multiscale method is compared with those of fine-scale models and of coarse-scale models with no subgrid treatment for several two-phase-flow scenarios. Numerical experiments involving two-phase incompressible flow and transport phenomena are carried out on high-resolution corner-point grids that represent explicitly example stratigraphic architectures found in real-life shallow-marine and turbidite reservoirs. The multiscale method is several times faster than the direct solution of the fine-scale problem and yields more accurate solutions than coarse-scale modeling techniques that resort to explicit effective properties. The accuracy of the multiscale simulation method with ALG-velocity basis functions is compared with that of the local velocity basis functions. The multiscale simulation results are consistently more accurate when the local-global method is employed for computing the velocity basis functions.
Lessons Learned From Applications of a New Organic-Oil-Recovery Method That Activates Resident Microbes
Authors: Zahner R.L.. L. , Tapper S.J.. J. , Marcotte B.W.G.. W.G. , Govreau B.R.. R. 
Published: January 2013

Summary
Using a breakthrough process, which does not require microbes to be injected, more than 100 microbial enhanced-oil-recovery (MEOR) treatments were conducted from 2007 to the end of 2010 in oil-producing and water-injection wells in the United States and Canada. On average, these treatments increased oil production by 122%, with an 89% success rate. This paper reviews the MEOR process, reviews the results of the first 100+ treatments, and shares what has been learned from this work.
Observations and conclusions include the following:
Screening reservoirs is critical to success. Identifying reservoirs where appropriate microbes are present and oil is movable is the key. MEOR can be applied to a wide range of oil gravities. MEOR has been applied successfully to reservoirs with oil gravity as high as 41° API and as low as 16° API. When microbial growth is appropriately controlled, reservoir plugging or formation damage is no longer a risk. Microbes reside in extreme conditions and can be manipulated to perform valuable in-situ "work." MEOR has been applied successfully at reservoir temperatures as high as 200°F and salinities as high as 140,000 ppm total dissolved solids (TDS). MEOR can be applied successfully in dual-porosity reservoirs. A side benefit of applying MEOR is that it can reduce reservoir souring. An oil response is not always observed when treating producing wells.
MEOR can be applied to many more reservoirs than thought originallys with little downside risk. This review of more than 100 MEOR well treatments expands the types of reservoirs in which MEOR can be applied successfully. Low-risk and economically attractive treatments can be accomplished when appropriate scientific analysis and laboratory screening are performed before treatments.
Nanoparticle and Microparticle Flow in Porous and Fractured Media— An Experimental Study
Authors: Alaskar Mohammed , Ames Morgan , Connor Stephen , Liu Chong , Cui Yi , Li Kewen , Horne Roland 
Published: January 2013

Summary
The goal of this research was to develop methods for acquiring reservoir pressure and temperature data near the wellbore and farther out into the formation and to correlate such information to fracture connectivity and geometry. Existing reservoir-characterization tools allow pressure and temperature to be measured only at the wellbore. The development of temperature- and pressuresensitive nanosensors will enable in-situ measurements within the reservoir. This paper provides the details of the experimental work performed in the process of developing temperature nanosensors. The study investigated the parameters involved in the mobility of nanoparticles through porous and fractured media. These parameters include particle size or size distribution, shape, and surface charge or affinity to rock materials.
The principal findings of this study were that spherically shaped nanoparticles of a certain size and surface charge compatible with that expected in formation rock are most likely to be transported successfully, without being trapped because of physical straining, chemical, or electrostatic effects. We found that tin-bismuth (Sn-Bi) nanoparticles of 200 nm and smaller were transported through Berea sandstone. Larger particles were trapped at the inlet of the core, indicating that there was an optimum particle size range. We also found that the entrapment of silver (Ag) nanowires was primarily because of their shape. This conclusion was supported by the recovery of the spherical Ag nanoparticles with the same surface characteristics through the same porous media used during the Ag nanowires injection. The entrapment of hematite nanorice was attributed to its affinity to the porous matrix caused by surface charge. The hematite coated with surfactant (which modified its surface charge to one compatible with flow media) flowed through the glass beads, emphasizing the importance of particle surface charge.
Preliminary investigation of the flow mechanism of nanoparticles through a naturally fractured greywacke core was conducted by injecting fluorescent silica microspheres. We found that silica microspheres of different sizes (smaller than the fracture opening) could be transported through the fracture. We demonstrated the possibility of using microspheres to estimate fracture aperture by injecting a polydisperse microsphere sample. It was observed that only spheres of 20 μm and smaller were transported. This result agreed reasonably well with the measurement of hydraulic fracture aperture (27 μm), as determined by the cubic law.
Colorado Drill-Cuttings-Injection Pilot Results
Authors: Kunze Kenneth R. , Romero Edgar E. , Duck Steven 
Published: January 2013

Summary
From December 2007 through April 2011, the operator conducted a two-phase drill-cuttings-injection pilot at the Piceance field in western Colorado to reduce the environmental footprint of drilling operations. This was the first subsurface injection of drill cuttings in Colorado, and it used a lost-circulation zone in the Wasatch G formation as the injection interval.
The first phase of the pilot was to assess the technical feasibility and formation response to injection. During this phase, water-based mud and drill cuttings from four wells were injected into a fifth well that was temporarily suspended at the intermediate casing and perforated in the Wasatch G formation. More than 40,000 bbl of fluid was injected during vacuum conditions with confirmed confinement to the target zone.
On the basis of the injection results, the pilot progressed to a second phase to assess the logistical requirements of transporting cuttings from multiple drilling locations to a central processing-and-injection site. The injection well selected had experienced lost returns in the Wasatch G when originally drilled and was completed as a dedicated injector. The pilot processed cuttings from three active rigs, and it demonstrated the capacity to process cuttings from more than six rigs.
The operator proved injection as a technically feasible option for drilling-waste disposal during full-field development at Piceance.
Special Considerations in the Design Optimization of the Production Casing in High-Rate, Multistage-Fractured Shale Wells
Authors: Sugden C.. , Johnson J.. , Chambers M.. , Ring G.. , Suryanarayana P.V.. V. 
Published: January 2013

SummaryTypical shale well completions involve massive, multistage fracturing in horizontal wells. Aggressive trajectories (with up to 20°/ 100 ft doglegs), multistage high-rate fracturing (up to 20 stages, 100 bbl/min), and increasing temperature and pressure of shale reservoirs result in large thermal and bending stresses that are critical in the design of production casing. In addition, when cement voids are present and the production casing is not restrained during fracturing, thermal effects can result in magnified load conditions. The resulting loads can be well in excess of those deemed allowable by regular casing design techniques. These loads are often ignored in standard well design, exposing casing to the risk of failure during multistage fracturing.In this work, the major factors influencing normal and special loads on production casing in shale wells are discussed. A method for optimization of shale well production casing design is then introduced. The constraints on the applicability of different design options are discussed. Load-magnification effects of cement voids are described, and a method for their evaluation is developed. Thermal effects during cooling are shown to create both bending stress magnification and annular pressure reduction caused by fluid contraction in trapped cement voids. This can result in significant loads and new modes of failure that must be considered in design. The performance of connections under these loads is also discussed. Examples are provided to illustrate the key concepts described. Finally, acceptable design options for shale well production casing are discussed.The results presented here are expected to improve the reliability of shale well designs. They provide operators with insight into load effects that must be considered in the design of production casing for such wells. By understanding the causes and magnitude of load-augmentation effects, operators can manage their design and practices to ensure well integrity.
Surfactant-Mediated Spontaneous Imbibition in Carbonate Rocks at Harsh Reservoir Conditions
Authors: Chen Peila , Mohanty Kishore K. 
Published: January 2013

Summary
The goal of this work was to pursue strategies to improve oil recovery in highly fractured carbonate reservoirs by altering the wettability from oil-wet to preferentially water-wet at high temperature (100°C or above), high salinity, and especially in high hardness environments. Cationic surfactants and anionic surfactants were investigated for their compatibility with hard brine at a high temperature. Sequestration agents were added to improve aqueous solubility. The performance of surfactant formulations was evaluated by measuring contact angles on calcite plates and spontaneous imbibition in originally oil-wet dolomite cores. Cationic surfactants altered the wettability of oil-aged calcite plates toward a more water-wet state in the presence of hard brines; oil recovery by spontaneous imbibition from dolomite cores was 50 to 65% of original oil in place (OOIP). Anionic surfactant formulations changed the carbonate wettability to strongly water-wet only when the brine salinity and divalent-ion concentration were reduced. The wettability could be altered in hard brines if a sequestration agent [e.g., ethylene diamine tetraacetic acid (EDTA)] is added to anionic surfactant formulations; up to 45% of OOIP was recovered by spontaneous imbibition. EDTA provides alkalinity, saponification, chelation of divalent ions, and dissolution of dolomite, which may contribute to the increase of imbibition rate and ultimate oil recovery in fractured carbonates.
Multiple Foam States and Long-Distance Foam Propagation in Porous Media
Authors: Ashoori E.. , Marchesin D.. , Rossen W.R.. R. 
Published: January 2013

Summary
Creation of low-mobility foam for enhanced oil recovery (EOR) is triggered by an increase in superficial velocity; thereafter, injection rate can be reduced to lower values, and strong foam remains at velocities at which weak foam was previously observed. Here, we consider whether strong foam created near an injection well can propagate to large distances from the well where superficial velocity is much smaller. We study strong-foam propagation with finite-difference simulations and Riemann solutions, applying a population-balance foam model that represents the multiple steady states of foam.
Our simulations show that strong foam cannot displace directly the initial high-water-saturation bank initially in the reservoir at low superficial velocities; it pushes a weak-foam state with lower velocity that in turn displaces the bank ahead. Our traveling-wave solutions show that strong foam propagates more slowly as superficial velocity decreases and stops propagating at yet lower superficial velocities, in agreement with the experiment. Failure of propagation occurs at superficial velocities greater than that at which the strong-foam state disappears; it raises concerns for long-distance propagation of strong foam created near the injection well. In the context of the model, it is not extraordinary destruction of foam at the front that slows the propagation of strong foam, but failure of foam (re-)generation at the front. Our model also represents for the first time a process where strong foam is created near the exit of a core and then propagates upstream, as seen in some experiments.
Single-Phase Inflow Performance Relationship for Horizontal, Pinnate-Branch Horizontal, and Radial-Branch Wells
Authors: Liu Huiqing , Wang Jing , Zheng Jian , Zhang Ying 
Published: January 2013

Summary
Horizontal and multibranch wells are likely to become the major means of modern exploitation strategies; inflow performances for these wells are needed. Because this paper considers the finite conductivity of a horizontal well, it establishes the inflow performance relationships (IPRs) for different branch configurations of horizontal wells. We find that the IPR of a horizontal well presents nonlinear characteristics and is similar to Vogel's equation, which has been used extensively and successfully for analyzing the IPR of a vertical well in a solution-gas-drive reservoir. Instead of the effect of a two-phase (oil and gas) flow in a reservoir described by Vogel's equation, the nonlinear characteristics of horizontal wells are mainly the result of pressure drops caused by friction, acceleration, and gravity along the horizontal wellbore. The nonlinearity coefficient presents the pressure drop along the major branch, and it is a function of major-wellbore length, major-wellbore diameter, oil viscosity, and relative roughness. Then, the horizontal-well IPR is used to study the performance of the pinnate-branch horizontal well and the radial-branch (horizontal lateral) well. The branch number, branch length, major-wellbore length, major-wellbore diameter, oil viscosity, and relative roughness are combined into grouped parameters to present the effect on the deliverability incremental ratio JH and the nonlinearity coefficient ratio Rv of the pinnate-branch horizontal well to the conventional horizontal well, which show regression relationships with the grouped parameters for pinnate-branch horizontal wells. In addition, another binomial relationship between the deliverability incremental ratio JV and the grouped parameter combined by branch number, branch length, and equivalent oil drainage diameter is obtained for radial-branch (horizontal lateral) wells. The new IPR also covers conventional horizontal wells and vertical wells (with no branch) because the deliverability incremental ratios JH and JV in both cases are unity. The IPR is very valuable for calculating the productivity of horizontal wells, pinnate-branch horizontal wells, and radial-branch wells.
Efficacy of and Effect on Tooth Sensitivity of In-office Bleaching Gel Concentrations: A Randomized Clinical Trial
Authors: Reis A , Kossatz S , Martins GC , Loguercio AD 
Published: January 2013

SUMMARYWith the aim of reducing the side effects of in-office bleaching agents, less-concentrated hydrogen peroxide (HP) gels have been released by manufacturers. We evaluated the tooth sensitivity (TS) and bleaching efficacy (BE) of two HP concentrations in this study. Gels containing 35% and 20% HP (HP35 and HP20, respectively) were applied on teeth of 60 caries-free patients. Color was recorded at baseline and one week after the first and second bleaching sessions using the Vita Classical shade guide. TS was recorded on a 0-4 scale. BE at each weekly recall was evaluated by Kruskall-Wallis and Mann-Whitney tests (α=0.05). Absolute risk of TS and its intensity was evaluated by Fisher exact and Mann-Whitney tests, respectively (α=0.05). After two bleaching sessions, color change of approximately eight tabs was obtained with HP35; whereas, with HP20 it was six tabs (p&lt;0.05). Only 26.7% (HP35) and 16.7% (HP20) of the participants reported TS, and no statistical differences were detected among them. Both in-office bleaching gels showed similar TS intensity, but the 35% HP agent produced faster bleaching.
Influence of Different Surface Treatments on Bond Strength of Resin Composite Using the Intrinsic Characterization Technique
Authors: Barcellos DC , Palazon MT , Pucci CR , Aizawa LH , Gonçalves SEP 
Published: January 2013

SUMMARYObjective: This study evaluated the influence of different surface treatments on the resin bond strength/light-cured characterizing materials (LCCMs), using the intrinsic characterization technique. The intrinsic technique is characterized by the use of LCCMs between the increments of resin composite (resin/thin film of LCCM/external layer of resin covering the LCCM).Materials and Methods: Using a silicone matrix, 240 blocks of composite (Z350/3M ESPE) were fabricated. The surfaces received different surface treatments, totaling four groups (n=60): Group C (control group), no surface treatment was used; Group PA, 37% phosphoric acid for one minute and washing the surface for two minutes; Group RD, roughening with diamond tip; and Group AO, aluminum oxide. Each group was divided into four subgroups (n=15), according to the LCCMs used: Subgroup WT, White Tetric Color pigment (Ivoclar/Vivadent) LCCM; Subgroup BT, Black Tetric Color pigment (Ivoclar/Vivadent) LCCM; Subgroup WK, White Kolor Plus pigment (Kerr) LCCM; Subgroup BK, Brown Kolor Plus pigment (Kerr) LCCM. All materials were used according to the manufacturer's instructions. After this, block composites were fabricated over the LCCMs. Specimens were sectioned and submitted to microtensile testing to evaluate the bond strength at the interface. Data were submitted to two-way analysis of variance (ANOVA) (surface treatment and LCCMs) and Tukey tests.Results: ANOVA presented a value of p&lt;0.05. The mean values (±SD) for the factor surface treatment were as follows: Group C, 30.05 MPa (±5.88)a; Group PA, 23.46 MPa (±5.45)b; Group RD, 21.39 MPa (±6.36)b; Group AO, 15.05 MPa (±4.57)c. Groups followed by the same letters do not present significant statistical differences. The control group presented significantly higher bond strength values than the other groups. The group that received surface treatment with aluminum oxide presented significantly lower bond strength values than the other groups.Conclusion: Surface treatments of composite with phosphoric acid, diamond tip, and aluminum oxide significantly diminished the bond strength between composite and the LCCMs.
Bond Durability of Self-etch Adhesive to Ethanol-Based Chlorhexidine Pretreated Dentin after Storage in Artificial Saliva and under Intrapulpal Pressure Simulation
Authors: Ali AA , El Deeb HA , Badran O , Mobarak EH 
Published: January 2013

SUMMARY

Objective
To evaluate the bond strength durability of a single-step self-etch adhesive to dentin pretreated with either ethanol-based chlorhexidine (ECHX) or water-based chlorhexidine (WCHX) after storage in artificial saliva and under intrapulpal pressure simulation (IPPS).

Methods
The occlusal enamel of 30 freshly extracted premolars was trimmed to expose midcoronal dentin. Roots were sectioned to expose the pulp chamber. Specimens were distributed over three groups (n=10) according to the dentin pretreatment used. In the first group, Adper Easy One (3M ESPE) was applied to the dentin surfaces according to the manufacturer's instructions (control group). In the second group, dentin was pretreated before bonding with 1 mL of 2% CHX diacetate dissolved in 100% ethanol (ECHX). The third group received the same pretreatment; however, CHX was dissolved in distilled water (WCHX). Pretreatment and bonding were carried out while the specimens were subjected to IPPS. Resin composite (Valux Plus, 3MESPE) buildups were made. After curing, specimens were stored in artificial saliva and under IPPS at 37°C in a specially constructed incubator (n=5/group) either for 24 hours or six months prior to testing. Thereafter, bonded specimens were sectioned into sticks with a cross section of 0.9 ± 0.01 mm2 and subjected to microtensile bond strength (μTBS) testing (n=25/subgroup) using a universal testing machine. Data were statistically analyzed using two-way analysis of variance (ANOVA) with repeated measures, one-way ANOVA , and Bonferroni post hoc tests (p≤0.05). Failure modes were determined using a scanning electron microscope.

Results
After 24 hours of storage, control and WCHX groups revealed significantly higher μTBS than the ECHX group. After six-month storage in artificial saliva and IPPS, only the WCHX group maintained its μTBS value. The predominant mode of failure was the mixed type, except for the ECHX group, which was mostly adhesive.

Conclusion
Pretreatment of the dentin with ECHX had a negative effect on bonding of the tested single-step self-etch adhesive; however, WCHX showed bond stability under IPPS.