bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Technique to Characterize Fracture Density Using Neutron Porosity Logs Enhanced by Electrically-Transported Contrast Agents
Authors: Tang Hewei , Killough John E. , Heidari Zoya , Sun Zhuang 
Published: September 2016

Abstract
Fracture density evaluation has always been challenging for the petroleum industry, although it is a required characteristic for reliable reservoir characterization. Production can be directly controlled by fracture density, especially in tight reservoirs. Previous publications introduced the method of using high thermal neutron capture cross-section contrast agents like boron carbide (CB4) to enhance the sensitivity of neutron logs to the presence of fractures. However, all of the studies focus on locating the proppants. In this paper, we propose to (a) enhance the propagation of the contrast agents into the secondary (natural and induced) fracture network using an externally applied electric field and (b) characterize the fracture density in un-propped area using the enhanced neutron porosity logs.
We perform numerical simulations to validate the feasibility of the proposed technique. A physical model derived from electrophoretic velocity and material balance formulations is proposed and solved to simulate the spatial distribution of contrast agents. Furthermore, we simulate neutron porosity logs by solving the neutron diffusion equation which significantly reduces the computing cost (from hours to a few seconds) compared to conventional use of the MCNP (Monte Carlo N-Particle Code) technique.
The simulation results confirmed that an external electric field can significantly enhance the transport of charged contrast agents into the secondary fracture network. Sensitivity analysis revealed that increasing particle zeta potential can efficiently decrease the transport time. Furthermore, we applied the introduced technique on synthetic cases with variable secondary fracture density ranging from 1% to 8%. The relative change of simulated neutron porosity before and after applying the electric potential field was up to 50% in a formation with 8% fracture density after applying an electric field for 6 hours. The proposed technique can potentially enable application of neutron porosity logs in fracture characterization, including assessment of secondary fracture density, if combined with other well logs.
Development of Permeability and Mechanical Properties of Class G Cement from Slurry to Set
Authors: Maharidge R. , Bottiglieri A. , Dighe S. S. , Holley A. , Zhang H. , Koch A. 
Published: September 2016

Abstract
As cement changes from liquid slurry to solid, its load-bearing response, strength and permeability characteristics are expected to change with time. Consequently the ability of any cement to withstand changes in wellbore pressure and temperature will be determined, in part, by the changes in elastic properties, failure criteria and permeability that occur over time. An experimental study of time evolution of mechanical and flow properties of Class G neat cement is presented in this study.
The objectives of this intra-laboratory test program were to answer the following questions: How rapidly do the mechanical and flow properties evolve over time? Can changes in microtexture be observed and correlated to those properties?What are the optimal times required to observe time-independent responses?What is happening to the water in the cement and does it correlate with the time evolution observed in mechanical properties and permeability?
Measurements of liquid permeability, static and dynamic elastic properties, compressive and tensile strengths, pore size distribution and microtexture and fabric photography were recorded over a 10 day interval.
The time evolution of mechanical and flow properties for 15.8 pound per gallon Class G cement and their relationships with water content are presented throughout the paper. Permeability is shown to dramatically decrease and equilibrate over the first 24-32 hours, while the mechanical properties continued to increase over a longer time period. The changes in mechanical/flow properties were strongly correlated to the decrease in water content and the shifting of pore size to smaller distribution functions. Complete stabilization of static elastic properties was not observed after 10 days, implying that, for certain cement formulations, these properties may need to cure for longer than industry standard times. From tests results, 96 hour cure times may be insufficient to characterize certain mechanical properties of wellbore cements. This study also sets a base standard for comparison with more complex cement chemistry's that are currently (and in the future) being used in oil-field operations. The authors also concluded that the use of NMR measurements of pore size and, in turn, water content correlate very well with conventionally used methods. Motivation for this study is based on limited data available on the simultaneous response of all critical wellbore cement properties from the very early stages of hydration to long-term set.
On the Exact Representation of Pressure Decay Tests: New Modeling and Experimental Data for Diffusivity Measurement in Gas - Oil/Bitumen Systems
Authors: Ratnakar R. R. , Dindoruk B. 
Published: September 2016

Abstract
Diffusion mixing is a dominant process in absence of convective mixing in various reservoir processes such as CO2 flooding of fractured reservoirs, heavy oil and bitumen recovery, solution gas drive processes, and gas re-dissolution process in depleted reservoir. In these processes, the diffusivity governs the rate and extent of mixing of light hydrocarbons/non-hydrocarbons with the oil that enhances the oil recovery through in-situ viscosities reduction. It is one of the key parameters for design and understanding of the displacement processes.
Due to its significance in various aspects of oil recovery processes, several experimental/theoretical studies are performed recently on the measurement of gas diffusivity in oils. Experimental work is most commonly based on the Pressure-decay concept due to its simplicity. The parameter estimation from these tests is based on the transient diffusion model, where the concentration/density gradient in gas phase is neglected or modelled with a transfer coefficient. However, these models are good for steady-state or late transient. Since the transfer coefficient concepts are validated only for steady-states (or near steady-state) in literature, its use in transient case must be investigated by analyzing the full diffusion model in both oil and gas phases. Therefore, in this article, the previous work [1] is extended and the diffusion process in pressure-decay set-up is experimentally investigatedthe transfer of gas from gas phase to the oil is captured properly through exact modeling based on the transient diffusion model in gas and oil phases coupled with continuity in state variable (using Henry's constant) and molar flux at the gas-oil interface;the exact solution of detailed pressure-decay (transient diffusion) model is developed and, the early and late transient solutions are analyzed;A robust inversion technique for parameter estimation is presented using exponentially decaying late transient data;Most importantly, the inversion technique is based on a linear regression and numerical integration rather than a non-linear regression. This integral based linear representation avoids the multiple solutions and can be used with limited dataset and/or when noise in the experimental data is significant.
Why Re-Fracturing Works and Under What Conditions
Authors: Asala H. I. , Ahmadi M. , Taleghani A. Dahi 
Published: September 2016

Abstract
Stimulated shale wells show sharp decline rates after several months of production imposing the need for rejuvenating production via re-fracturing or other methods. The sharp decline in production from shale gas/oil wells is attributed to full or partial closure and damage of the induced fracture network within the rock. The poor economic conditions stirred by low oil prices has persuaded operators to consider re-fracturing as an affordable option but the mechanisms behind this technique is not fully understood. In this paper, we utilize a fully coupled model to understand stress re-distribution and identify different modes of fracture closure during production from initial hydraulic fractures. Rock creep, proppant failure and differential fluid depletion are identified as primary causes of closure within shale fracture networks. We incorporate these phenomena into a poroelaso-plastic model that simulates fracture conductivity evolution during production, and re-fracturing treatments illustrated by re-fracture propagation, fracture coalesce or fracture extension along pre-existing fractures. This methodology provides a realistic initial condition to simulate varying re-fracture designs - different treatment schedules and fracturing fluids. The Influence of degradable mechanical and non-mechanical diverters is also incorporated in this model.
Our results reveal major stress redistribution in the fracture network especially at the intersections due to depletion. The results show how fracture closure at the fracture intersections causes abrupt or time dependent shrinkage of the drainage area. Under certain conditions, re-fracturing may effectively open up these bottlenecks while in extreme situations, it creates new fractures which reorient obliquely. Results also reveal the role of in-situ stress anisotropy, magnitude of depletion and complexity of fracture networks in the successful re-fracturing of lower- clay content naturally fractured formations such as the Barnett shale. The results do not suggest strong dependency on stress anisotropy and natural fractures orientation in high clay content reservoir rocks like Haynesville or Marcellus. It shows the quantifiable effect of creep on closure rate and conductivity loss. Results show diverters have a profound effect on the expansion of the re-fracture network, although it hinders reactivation of some clogged fractures. Using adaptive cohesive elements provides the opportunity to model longitudinal, transverse or oblique re-fracture propagation.
The Proposed model introduces a realistic fracture closure mechanism and stress re- distribution during drainage, prior to re-fracturing. This plays a vital role in explaining initial fracture extension, re-frac propagation, fracture coalesce, re-fracture re-orientation, and therefore the effectiveness of re-fracturing treatments. This model offers a practical tool for identifying potentially successful re-fracturing candidates.
New Wireline, In-situ, Downhole Fluid Compositional Analyses to Enhance Reservoir Characterization and Management
Authors: Hursan Gabor , Mark Ma S. , Soleiman Wael , Eyuboglu Sami , Sethi Neeraj , Guergueb Nacer 
Published: September 2016

Abstract
Physical fluid samples collected in situ provide evidence for verification of exploration prospects, optimization of formation evaluation and reservoir production. Downhole fluid analyzers (DFA) are developed essentially to ensure the quality of formation samples. Advanced DFA are emerging for more advanced fluid compositional analyses in situ, as well as for studying the effect of pressure on fluid physical and chemical properties, those typically determined in the laboratories. Laboratory tests such as PVT (pressure-volume-temperature) analysis are still used as reference in reservoir engineering, provided the sample tested is representative of formation fluid and also differences among different laboratories are minimized.
This study focuses on crude oil compositional analyses during pumpout with a wireline formation tester. It summarizes experience with the in-situ measurement of methane, ethane, propane, saturates, aromatics and GOR based on multivariate optical computing (MOC) conducted at over 200 pumpout stations in a total of 37 wells drilled with a variety of inclinations, bit sizes, drilling fluids in several oil and gas fields. The results and lessons learnt enhanced technology development including hardware improvements, capability expansion for new components, processing software upgrades and the foundation of a local center of excellence for operations and study support.
Examples of individual pumpout stations within the context of an integrated petrophysical analysis of wireline logs are presented to demonstrate data quality control and basic interpretation in oil and gas wells in the presence of water- and oil-based muds. The data are cross-validated by correlations with laboratory and other sensor data. Fine but consistent field-wide compositional variations suggest the possibility of new geological understanding and advanced reservoir fluid modeling from the newly acquired DFA data base.
New Pseudo-Pressure and Pseudo-Time Functions for Multiphase Flow
Authors: Shahenda Mahran , Ahmed H. El-Banbi 
Published: September 2016

Abstract
The development of pressure transient analysis was based on the assumption of a single phase slightly compressible fluid. This assumption was later relaxed to handle dry gas reservoirs and multiphase situations. The literature reported several methods for multiphase well test analysis [e.g., Perrine-Martin method (1956), pressure squared method proposed by A1-Khalifah (1987), and the two-phase pseudopressure function by Raghavan (1976), and 3-zone Fevang and Whitson approach (1995)].
In this paper, we develop new formulation for generalized multiphase pseudo-pressure and pseudo-time functions that can handle any type of multiphase flow system. In particular, the new formulation uses the modified black-oil (MBO) approach and can handle volatile oils and gas condensate reservoirs in more accurate ways than presented previously in the literature. These generalized multiphase pseudo-functions were validated through the analysis of many simulated drawdown and pressure buildup tests covering comprehensive inner (radial wells, partial penetration, fractured, and horizontal wells). The simulated cases also covered all multiphase flow situations. In every simulated case, analysis using the new functions was compared with single phase, Perrine-Martin, and the multiphase approaches proposed by Raghavan and Fevang and Whitson analyses. The new technique proved to be the most accurate among the other techniques. The new technique also uses one generalized form to handle any multiphase situation including volatile oils and gas condensates. As an example, application of the new generalized multiphase pseudo-functions to analyze transient data generated in gas-water multiphase flow system, at different water cut values; it was found that the new multiphase pseudo-function technique was able to predict the flow capacity with error percentage less than 10% when the water cut value was less than 50%. This was at least 2 folds better than other existing techniques. It was also found that this error percentage increased when the water cut value exceeded 80%.
Applying the new pseudo-functions techniques also improves the quality of data for analysis in multiphase flow situations.
Hydraulic Fracture Propagation in a Highly Laminated Shale Reservoir with Complex Natural Fracture Network - Case Study Using Higher-Accuracy, Full 3-D Simulation
Authors: Hussain Maaruf , Saad Bilal , Negara Ardiansyah , Elgassier Mokhtar , Agrawal Gaurav , Sun Shuyu , Abdullah King 
Published: September 2016

Abstract
It is often reported that around 60% of hydraulic fracturing stages are ineffective. If so, it is likely that the design accuracy is limited by the current state of modeling and hydraulic fracture (HF) simulations. Our study presents a new alternative – a full 3-D simulation with geomechanics coupled to fluid flow. With the conventional simulation, it is extremely hard to model opening of weak lamination (Lam) and nearly impossible to generate induced horizontal fractures against the vertical overburden stress. However, horizontal fractures are routinely evident in shale reservoirs as healed fractures observed along the bedding planes. Hence, the need and importance of a true 3-D simulator that could incorporate complex geology and dynamically simulate fracture propagation by accounting for realtime changes in geomechanics and fluid pressures. Case study uses shale reservoirs, which are heavily laminated with complex natural fractures (NFs). Numerical simulations consisted of four separate coupled modules - geomechanics, hydrodynamics, a geomechanical joint model for interfacial resolution, and an adaptive remeshing module. Reservoir stress condition, rock mechanical properties, and injected fluid pressure dictate how fracture elements could open or slide. Critical stress intensity factor was used as a fracture criterion governing the generation of new fractures or propagation of existing fractures and their directions. Simulation was run on a Cray XC-40 HPC system. Typical laminated shale reservoirs anisotropic geomechanical properties obtained from literature were used to estimate a 3-D geomechanical model and NF network. HF geometry was significantly different in the presence of weak bedding, compared to when bedding was strong enough to transmit crack tip stresses across the interface. Significant amounts of fracturing fluid can be diverted into creation of horizontal fractures, even when the pressure was below the vertical stress, once bedding discontinuities are activated. Choices of NF network and Lam thickness significantly affected observed fracture propagation. The value of 3-D modeling was clearly established. This method provides more accurate solutions for stimulation design optimization, e.g., landing points, number of stages, number of clusters, spacing between stages, and stimulated reservoir volume.
Impact of Internal Magnetic Gradients on Nuclear Magnetic Resonance Measurements and NMR-Based Pore Network Characterization
Authors: Tandon Saurabh , Heidari Zoya 
Published: September 2016

Abstract
NMR (Nuclear magnetic Resonance) measurements have been extensively used for characterizing porosity and pore size distribution with assumption of constant magnetic field gradient within porous media. However, internal gradients of magnetic field generated due to the presence of paramagnetic or diamagnetic centers such as clay particles can significantly affect NMR response and the resulting interpretation for pore-size distribution and porosity. In this paper, we quantify the impact of internal magnetic gradients and spatial distribution of matrix components such as clay minerals on NMR response using pore-scale NMR numerical simulations. We also quantify the influence of the aforementioned parameters on the NMR-based evaluation of porous media.
We used finite volume method to numerically solve Bloch equations (Bloch 1946) and simulated magnetization decay in porous media. We cross-validated the reliability of numerical simulations using analytical solutions given for spherical pores in different diffusion regimes. The model is then used for simulation of NMR response in the pore-scale images of sandstone and carbonate rocks. We developed synthetic cases based on actual rock images covering a wide range of spatial distribution of clay minerals (i.e., paramagnetic or diamagnetic centers) to quantify the sensitivity of NMR decay to internal magnetic gradients. We quantified the sensitivity of NMR response for distribution of clays as random dispersion in the rock grains, as thin laminae in the rock and as thin layers on the surface of grains.
The results showed that at low concentration (e.g., 0.3%-0.7%) of dispersed clay, there is negligible impact of internal magnetic gradients on magnetization decay. At higher concentration of dispersed clay (e.g., 5.1%-7.3%), we observed significant impact of internal magnetic gradients on magnetization decay. The presence of clay minerals can cause 53% variation in the location of transverse relaxation time constant (T2) and up to 67% relative error in assessment of dominant pore sizes. We also observed that structural clays even at high volumetric concentrations of 40% produce negligible effect on NMR measurements. Shale laminations containing clay were found to produce an effect of up to 17.5% on T2 relaxation time constant that could cause a relative error of 23.1% in estimates of dominant pore size in the rock. The outcomes of this paper can potentially improve conventional techniques of pore network characterization (pore-size distribution and pore volume) in the presence of clay minerals where internal magnetic gradients are not negligible.
Improved Characterization of Carbonate Rock Properties: A Multiphysics Integrated Approach
Authors: Kraishan Ghazi M. , Ma Shouxiang Mark , Dyshlyuk Evgeny , Al-Ofi Salah M. , Valori Andrea , Abdallah Wael , Crary Steve 
Published: September 2016

Abstract
Single subsurface measurement of formation properties cannot provide a complete assessment of the rock and fluid properties at reservoir conditions. The key to successful formation evaluation is through integration of data obtained with different physics, as demonstrated in this study of carbonate rock characterization.
Carbonate formations are complex owing to their complicated pore structure resulting from different depositional environments and diagenesis. Derived rock petrophysical properties from multiphysics measurements of acoustics, resistivity, dielectric, and nuclear magnetic resonance (NMR) are compared with the "true" rock properties determined directly through core analyses at ambient and/or reservoir conditions. 20 core plugs were studied at both fully and partially saturated states.
Results indicate that temperature is a major factor affecting the dielectric, NMR, and resistivity signals whereas pressure has less impact. Although, the selected samples were carefully chosen to represent the dominant lithofacies and rock lithologies, the NMR 1D porosity profile exhibit a heterogeneous nature for some of the plugs. After inversion of the dielectric data, the cementation factor and saturation exponent were obtained from both dielectric and resistivity experiments. In addition, the inverted shallow resistivity (Rxo) from dielectric agrees well with Rxo obtained from the resistivity measurement, demonstrating measurement consistency.
Integration of the multiphysics measurements enables improved characterization of carbonate rocks. The integration procedure is based on a mathematical algorithm comparing variability in the input parameters. The added value of the current work is shown when integrating and calibrating these results with logs. It enhances the petrophysical interpretation, reduces the uncertainty in some of the petrophysical parameters, and increases understanding toward better field development strategies.