bluuebunny/crossref_metadata_2025_split huggingface dataset:
Capillary Pressure Prediction from Rock Models Reconstructed Using Well Log Data
Authors: Jin Guodong , Manakov Artem , Chen Jinhong , Zhang Jilin 
Published: October 2012

Abstract
Capillary pressure (Pc) is one of the main factors governing the hydrocarbon distribution within a reservoir. Its determination usually requires expensive, time-consuming laboratory experiments on a restricted number of core samples, while the continuous Pc profile of a well is practically derived from the nuclear-magnetic-resonance (NMR) downhole logging measurements. This paper presents a robust and inexpensive method of predicting the continuous Pc profile of a well from rock models reconstructed using various well log data. The approach first generates a representative rock model for the formation at each given depth of interest. The rock model is constrained by formation parameters derived from the logging data and accounts for diagenetic processes such as compaction and precipitation of carbonate and clay minerals. Simulations of fluid flow and primary drainage are then performed on rock models to determine the Pc curve and absolute permeability.
To test and validate our modeling approach, we select 16 sandstone core samples from various geologic settings to perform laboratory measurements and numermical simulations. Rock models are reconstructed using the measured grain-size distributions and grain mineralogy from core samples. The drainage Pc curves derived from rock models match well with laboratory measurements on the corresponding core samples, while Pc curves converted from NMR T2 distributions using the simple relationship of PcT2= ξ show differences in shape. Furthermore, the computed permeability of rock models show good agreement with the core permeability, mostly falling within the ± 2 times measurements. We have also applied the rock modeling technique to predict the continuous Pc and permeability profiles of a well. Formation grain-size distribution and mineralogy at each depth are derived from downhole measurements and used to generate rock models. Generally, our computed permeability falls within the same order of magnitude as the measurements on core samples from the same depth. The simulated Pc curves differ in shape from those converted from NMR T2 distributions. However, in this case it is unknown which one represents the real Pc curve due to the absence of laboratory core measurements.
3D Modeling of Multistage Hydraulic Fractures and Two-Way Coupling Geomechanics - Fluid Flow Simulation of a Horizontal Well in the Nikanassin Tight Gas Formation, Western Canada Sedimentary Basin
Authors: Gonzalez Laureano , Nasreldin Gaisoni , Rivero Jose , Welsh Pete , Aguilera Roberto 
Published: October 2012

Abstract
Unconventional gas is stored in extensive areas known as Basin Centered Continuous Gas Accumulations. While the estimated worldwide figures differ significantly, the consensus among the studies relating to unconventional gas resources is that the volumes are gigantic. However, the low permeability in these types of reservoirs usually results in a very low recovery factor.
To help unlock these resources, this paper presents a new and more accurate way of simulating multi-stage hydraulic fracturing in horizontal wells in three dimensions (3D) using single and dual porosity reservoir models. In this approach, the geometry (not necessarily symmetric) and orientation of the multiple hydraulic fractures are driven by the prevailing stress state in the drainage volume of the horizontal well. Once the hydraulic fracturing job is accurately modeled in 3D, two-way geomechanical coupling is used to history match the produced gas from a horizontal well drilled in the Nikanassin naturally fractured tight gas formation (Western Canada Sedimentary Basin).
Traditionally, the most widely used approaches have their roots in semi-analytical calculations simplifying the fracturing system to a planar feature propagating symmetrically away from a line source of injection. In contrast, the computed results presented in this study show that the incorporation of geomechanical effects gives a more realistic representation of the orientation and geometry of hydraulic fractures. Reduction in permeability of the natural and hydraulic fractures due to pressure depletion results in more realistic production predictions when compared with the case where geomechanical effects are ignored.
The telling conclusion, in light of the computed results, is that the field of hydraulic fracturing provides an object lesson in the need for coupled 3D geomechanical approaches. The method presented in this paper will help to improve gas rates and recoveries from reservoirs with permeability values in the nano-Darcy scale.
Three-Phase Compositional Modeling with Capillarity in Heterogeneous and Fractured Media
Authors: Moortgat Joachim , Firoozabadi Abbas 
Published: October 2012

Abstract
Capillary pressure can have a significant effect on multiphase flow in heterogeneous and fractured media, even when there is species transfer between the phases. Modeling the combined non-linearities from phase behavior and capillarity in the multiphase flow equations for heterogeneous and fractured media may be one of the most complicated problems in reservoir simulation. In this work, we present an efficient numerical scheme that uses higher-order methods for the first time to model capillarity in fully compositional three-phase flow. We introduce a simple local computation of the capillarity pressure gradients in the fractional flow formulation in terms of the total flux. Complications arising from gravity and capillarity are resolved in the upwinding with respect to phase fluxes. Our choice of the Mixed Hybrid Finite Element Method for the pressure and flux fields is an accurate and natural approach to compute the capillary pressure gradients and fluxes at the interface between regions of different permeabilities. We present various examples on both core- and large-scales to demonstrate powerful features of our capillary pressure modeling and the upwinding with gravity and capillary pressure. The examples include layered and fractured domains.
Remote Triggering of Large Events during Hydraulic Fracture Stimulations
Authors: Bowman S. , Urbancic T. , Baig A. 
Published: October 2012

Abstract
Hydraulic fracture stimulations result in the re-distribution of stress adjacent to the treatment well that in turn may result in the triggering of seismicity. Generally, seismicity only occurs when the triggering source, such as the injection of proppants, acts to drive the pre-existing stress field closer to failure levels of susceptible fractures/faults. If we consider that the observed seismicity is a function of the stress state and its interaction with the fracture network, under some conditions, it might be possible that seismicity may then occur at distances beyond the volume related to or directly influenced by the stimulation. Currently, the extent of seismic influence, including the potential for remote mobilization of pre-existing structures, the potential for out-of-zone fluid communication, and the relative stress and stress transfer conditions leading to large event occurrence (M &gt; 0) are not well understood.
In this paper, we investigate the spatial and temporal variations in microseismicity associated with hydraulic fracture treatment of a shale play in North America during which distant larger magnitude events were triggered. These events, in this example, were located up to several hundred metres away from the stimulations, and in some cases in different formations from the reservoir host rock. These datasets, including calculated source parameters such as apparent stress and seismic moment, provide the basis for examining the conditions under which remote structures can be activated and how the distribution of microseismicty can be used to establish the region of stimulation influence. Based on these observations we postulate on the potential of triggering events remotely.
Pressure-Dependent Natural-Fracture Permeability in Shale and its Effect on Shale-Gas Well Production
Authors: Cho Y. , Apaydin O. G. , Ozkan E. 
Published: October 2012

Abstract
This paper presents the results of an experimental study of pressure-dependent natural-fracture permeability in tight, unconventional reservoirs. Bakken cores are used in the experiments. For the purpose of this paper, pressure-related permeability losses in hydraulic fractures and matrix system are not considered. Experimental data are used to screen the stress-dependent matrix-permeability correlations available in the literature for application to shale fractures. Selected correlations are matched with the data to delineate the reasonable ranges of the correlation coefficients for shale fractures. The applications of the correlations over practical ranges of pressure drop in shale reservoirs indicate over 80% reduction in fracture permeability, with most of the permeability loss occurring during the initial pressure drop. To appraise the effect of pressure-dependent natural-fracture permeability on shale-gas production, experimentally developed correlations are incorporated in an analytical model of a fractured horizontal well surrounded by a stimulated reservoir volume. The model is used to history match the performances of two wells in the Barnett and Haynesville formations. It is shown that the effect of pressure-dependent natural-fracture permeability on shale-gas-well production is a function of the permeability of the matrix system. If the matrix system is too tight, then the retained permeability of the natural fractures may still be sufficient for the available volume of the fluid when the system pressure drops.
Nano to Macro Mechanical Characterization of Shale
Authors: Kumar Vikas , Sondergeld Carl H. , Rai Chandra S. 
Published: October 2012

Abstract
We report on a nano-indentation study of shales from the Barnett, Woodford, Ordovician, Eagle Ford and Haynesville plays. Careful selection of load and displacement during nano-indentation testing yields micro to macro-mechanical properties, Young's modulus and hardness, of shale. Scanning Electron Microscope coupled and nano-indentation were used to study the mechanical behavior of kerogen. The measured Young's modulus of kerogen varied from 5 to 9 GPa. Mineralogy is found to play an important role in controlling mechanical properties of shales; an increase in carbonate and quartz content is correlated with an increase in Young's modulus whereas, an increase in TOC, clay content and porosity decreases Young's modulus. Close agreement is found between indentation moduli measured on small samples (mm scale) and dynamic moduli calculated from velocity and density measurements made on larger samples (centimeter scale). Tests conducted on cuttings provided results comparable to measurements made on larger core samples. Nano-indentation can provide a viable means of assessing quantitative measure of shale "fraccability."
A Combined Experimental and Theoretical Investigation on Application of Wettability Modifiers in Gas-Condensate Reservoirs
Authors: Fahimpour J. , Jamiolahmady M. , Sohrabi M. 
Published: October 2012

Abstract
Well productivity of gas-condensate reservoirs can be severely impaired by condensate/water blockage around the wellbore. Improving resident phase mobility by altering the rock wettability to intermediate gas-wet has been proposed as an efficient and long-term remedial solution to this issue.
Evaluating the performance of such a costly chemical treatment process for real field applications through experimental and theoretical investigations is crucial, something which has been addressed here. In this work different groups of chemicals were used to alter wettability of various carbonate rock surfaces. The impact of a number of important parameters on the reservoir performance was also studied in our numerical simulation exercise.
The main findings of performed experiments are: a) anionic and to lesser extent non-ionic fluorochemicals are effective wettability modifiers for carbonate minerals, b) by increasing the chemical concentration typically oil-repellency increases and water-repellency either does not change or decreases, c) permeability damage due to excess chemical deposited on mineral surfaces becomes more sever in low permeability rocks. Using alcohols instead of water-based solvent and/or filtration of chemical large aggregates can to some extent reduce the undesired rock permeability impairment and d) temperature has a significant albeit non-monotonic effect on the interaction between chemical and the rock surface, especially at its elevated limits.
Numerical simulation results demonstrated that alcohol (compared to water)-based chemical solutions have better performance, especially at higher volumes of the injected chemical and in tighter rocks due to the reduced adverse effect of solution back-flow. The improvement factor of relative permeability and durability of chemical treatment showed significant impact on increasing the benefits of such a process. On the other hand, reduction of the rock permeability due to excessive chemical deposition had considerable adverse effect on the treatment performance, especially when a water-based solvent was used.
These results provide valuable practical guidelines on design and application of such treatment solutions for field trials.
A New Three-Dimensional, Compositional, Model for Hydraulic Fracturing with Energized Fluids
Authors: Ribeiro Lionel H. , Sharma Mukul M. 
Published: October 2012

Abstract
While several three-dimensional (3D) fracturing models exist for incompressible water-based fluids, none are able to capture the thermal and compositional effects that are important when using energized fluids. This paper introduces a new 3D, compositional, non-isothermal, fracturing model designed for compressible fracturing fluids. The new model predicts changes in temperature and fluid density. These changes are treated on a firm theoretical basis by using an energy balance equation and an equation of state, both in the fracture and in the wellbore. The model is capable of handling any multicomponent mixture of fluids and chemicals. Changes in phase behavior with temperature, pressure, and composition can be modeled.
A new simulator has been developed based on the compositional model presented in this paper. The simulator is validated for traditional fluid formulations against known analytical solutions and against a well-established commercial fracturing simulator. Results from the new simulator are then presented for energized fluids such as CO2 and LPG. This tool is specifically suited for fracture design in formations in which energized fluids constitute a viable alternative to traditional fracturing fluids. This is notably the case in reservoirs that are depleted, under-saturated, or water-sensitive.
Cyclic Hysteresis in Three-Phase Relative Permeability Applicable to WAG Injection: Water-Wet and Mixed-Wet Systems under Low Gas/Oil IFT
Authors: Fatemi S. Mobeen , Sohrabi Mehran 
Published: October 2012

Abstract
One major problem in the prediction of the performance of Water Alternating Gas (WAG) process is the uncertainty associated with the changes in three-phase relative permeability (kr) values of oil, gas and water in different cycles, which is known as cyclic hysteresis. In this work we have investigated the effect of cyclic injection on three phase kr by performing a series of coreflood experiments under both water-wet and mixed-wet conditions. WAG experiments started with water injection (I) followed by gas injection (D) and this cyclic injection of water and gas was repeated (IDIDID). Three-phase relative permeabilities were obtained analytically from the coreflood data using an extension of Buckley-Leveret formula to three-phase flow.
The results show the importance of properly accounting for irreversible kr hysteresis loops (especially for gas and oil) in the processes involving cyclic injection under three-phase flow conditions. Gas relative permeability (krg) dropped in successive cycles under both water-wet and mixed-wet conditions krg hysteresis was larger in the water-wet system compared to the mixed-wet case. The results also reveal cyclic hysteresis for oil relative permeability (kro), which tends to increase in successive gas injection periods. The improvement in kro was larger in the water-wet system. In both water-wet and mixed-wet systems, the largest krw hysteresis happens for the transition from two-phase (oil/water system) to three-phase system (from 1st water injection into 1st gas injection) and the subsequent WAG cycles does not show much hysteresis for krw in our experiments.
The paper also offers insights into and explanations for the observed cyclic hysteresis behaviour based on our understanding of the pore-scale and core-scale displacement mechanisms involved in WAG injection. The results highlight some serious shortcomings of the existing reservoir simulators for reliable simulation of oil recovery processes involving three-phase flow and flow reversal.
Effect of Gas Diffusion on Mobility of Foam for EOR
Authors: Nonnekes L. E. , Cox S. J. , Rossen W. R. 
Published: October 2012

Abstract
Transport of gas across liquid films between bubbles is thought to weaken foam by increasing bubble size. It is cited as one reason why CO2 foams for enhanced oil recovery (EOR) are usually weaker than N2 foams and why steam foams are weaker than foams of steam mixed with N2. In porous media, diffusion can rapidly destroy bubbles smaller than a pore, but in EOR foam bubbles are thought to be larger than pores, making the role of diffusion moot. Previous analysis of diffusion in foam in porous media has focused on diffusion between immobile bubbles smaller than the pores.
We examine here the effect of inter-bubble gas diffusion on flowing bubbles in a simplified model of a porous medium (a periodically constricted tube) and in particular its effect on the bubble-size distribution and capillary resistance to flow. We use the solution for bubble shapes, curvatures and pressure differences between bubbles from previous studies of bubble movement through periodically constricted tubes to estimate the diffusion rate between bubbles. We fit our model parameters to mass-transfer data for foam films between bubbles and realistic convection rates and pore geometries for foam EOR processes. Bubbles somewhat smaller than a pore can indeed disappear by diffusion as the bubbles move. For bubbles larger than a pore, as expected in EOR, diffusion does not affect bubble size. Instead, diffusion actually increases capillary resistance to flow (i.e., makes foam stronger): lamellae spend more time in positions where lamella curvature resists forward movement.
When fit to pressures and diffusion and convection rates representative of field application of foams, diffusion is not expected to alter the bubble-size distribution in a foam, but instead modestly increases the resistance to flow. The reason for the apparent weakness of CO2 foam therefore evidently lies in factors other than CO2's large diffusion rate through foam.
Logging-While-Drilling Cement Evaluation: A Case Study from the North Slope, Alaska
Authors: Longo Joe , Hupp Douglas , Blyth Matthew , Alford Jeff 
Published: October 2012

Abstract
Alaska state requirements as well as sound engineering practice require that oil and gas operators investigate the zonal isolation in the annulus of water injection wells. Conventional cement evaluation can be a time-consuming and expensive process, especially in high-angle or horizontal wells in which the wireline tools must be conveyed with a tractor or on drillpipe. Cased-hole LWD sonic data was acquired in a North Slope, Alaska, well to evaluate the cement bond zonal isolation in the casing by attenuation and transmission analysis. The LWD data was compared with a traditional wireline cement evaluation logs to validate the application. This paper provides a case study of the techniques used to acquire process and interpret logging-while-drilling (LWD) sonic logs for cement evaluation.
In this case study, a horizontal lateral section was drilled after setting and cementing the intermediate casing string. The interval to be evaluated for zonal isolation was behind this intermediate casing. LWD sonic data were acquired for cement evaluation purposes while tripping in the hole to drill out the intermediate casing cement shoe prior to drilling the horizontal section of this well. The ability to acquire cement evaluation data during the normal drilling practice provides significant cost savings over traditional wireline cement evaluation methodologies.
This paper discusses the theoretical basis for using LWD sonic data for cement evaluation, planning procedures, data acquisition, and data processing. A comparison of the LWD sonic cement evaluation data with traditional wireline cement evaluation data that was used to validate this technique is provided. Additionally, the advantage of integrating the LWD cement evaluation option into the drilling process will be described.
High-Density Brine-Based Fracturing Fluid for Ultra-Deep Fracturing Stimulation
Authors: Gupta D. V. , Carman Paul , Venugopal Rupa 
Published: October 2012

Abstract
With the oil and gas industry looking ever deeper for hydrocarbons, well control and completions have become important challenges to overcome. Ultra-deep wells usually have pressured or over-pressured formations and require heavyweight brines to control hydrostatic pressures. Completions that once used fresh water or sea water are no longer feasible due to the much higher surface treating pressure requirements, which current equipment cannot sustain. Consequently, the industry has been interested in using heavyweight brines as a base for fracturing fluids. However, the practice is limited by the polymers that can be used in particular base brine. The most commonly used systems employ NaBr, usually in the range of 11.0 to 12.5 ppg, with a modified guar, buffer, crosslinker and other additives. The systems are finicky, hard to break and the NaBr brines have higher cost compared to chloride brines, prompting a search for alternative, less expensive solutions.
A newly developed system will viscosify any brine from 11.0 to 19.2 ppg, with only gellant, surfactant and breaker added on the fly to the base fluid. No buffer, crosslinker or other additives are necessary, which greatly improves operational efficiency, especially offshore. The unique patented polymer system creates an association with the salt solution to generate viscosity. The system can be used with lower-cost brines or blends based on NaCl, NaBr, CaCl2 and CaBr2. The resulting fluid is very elastic and has excellent proppant transport characteristics. The system can be broken efficiently to achieve good regain conductivity. This paper will present the chemistry and results of complete laboratory testing to evaluate the fluid for fracturing applications.