bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unconventional Reservoir Geology of the Neuquén Basin Argentina
Authors: Barredo Silvia , Stinco Luis 
Published: October 2014

Abstract
The Neuquén Basin is one of the most important hydrocarbon producing basins of Argentina and is presently being explored and restudied because of its unconventional reservoirs rocks. Since the basin resulted from thermo-mechanical processes acting on a structured lithosphere a geodynamic analysis was needed for interpreting the regional distribution of its depositional sequences and their associated unconventional reservoirs. This basin corresponds to a continental rift developed during differential intraplate stresses derived from a backarc extension. Most of the border fault systems consist of reactivated structures whose attitude with respect to the extensional regime controlled the geometry of the basin. The infilling consists of clastic and pyroclastic rocks sourced from continental alluvial-fluvial environments during Triassic to Early Jurassic times to alternative marine-continental during most of the Jurassic to Cretaceous times. This evolution is consistent with troughs growing larger through time but being affected by recurrent extensional pulses during accelerated basin subsidence and or seal level change overlapped by compressional forces which resulted in a complex environmental relationship throughout the basin. Consequently, vertical and lateral facies variations are present in reservoir rocks along the basin which requires a detail analysis to proper model the petroleum systems. Especially because significant hydrocarbon source rocks of this basin, that can be produced as unconventional, like the highly known Vaca Muerta Formation. The aim of the present contribution is then to propose an integrated, geodynamic and tecnostratigraphic model to the Neuquén Basin which can improve the understanding of its geological evolution particularly considering that the estimated resources related to unconventional reservoirs are 455 TCF.
Steady-State Relative Permeability Measurements, Temperature Dependency and a Reservoir Diatomite Core Sample Evolution
Authors: Vega B. , Kovscek A. R. 
Published: October 2014

Abstract
Evaluation of thermal-recovery processes requires relative permeability functions, how such functions change with temperature, as well as the evolution of rock permeability and porosity as floods progress. There are significant challenges associated with estimating relative permeability, and its temperature dependence, from laboratory data including the accuracy of data and generalized assumptions in the interpretation technique. Direct measurements of relative permeability curves through the steady-state method are ideal and scarce, in particular for low-permeability systems. This study reports the results of a long-term study to measure the steady-state oil/water relative permeability as a function of temperature of a core sample from a low-permeability, siliceous shale, diatomite reservoir. All tests were isothermal, carried out at temperatures ranging from 45 to 230 °C (113 °F – 446 °F). In-situ phase saturation was monitored using an X-ray CT scanner. Results obtained show a systematic shift towards increased water wettability with increasing temperature. Dependence of endpoint phase saturation and relative permeability with temperature is apparent from these measurements thereby confirming the transition to water-wetness with increasing temperature previously derived from spontaneous imbibition experiments on previous diatomite samples. A post-mortem analysis of sample porosity distribution and rock quality reveals the evolution of additional petrophysical attributes as a result of two years of thermal flooding.
A One-Year Production Study between Cemented Multistage and Openhole Completion Technologies for Vertical Wells in the Permian Basin
Authors: Lohoefer Darrel , Keener Brett , Ezeldin Saiff , Snyder DJ 
Published: October 2014

Abstract
The Permian Basin is one of the top five resource plays in the United States and consists of a number of stacked pay zones. Two of these formations, the Wolfcamp shale and Bone Spring (together referred to as the Wolfbone), deliver a pay zone thickness from approximately 1,000 to 1,500 ft. They are made up of several different layers of organic rich shales, intermingled with sandstone and siltstone. Horizontal completions in the shales are just beginning and have yet to be proven; however, operators are successfully exploiting the reserves through vertical wells.
While a mature exploration area, the completion of the thick shale intervals is a new target formation. To date, two vertical completion methods have been utilized to gain access to hydrocarbons: openhole multistage systems (OHMS) and the conventional cemented liner, "plug and perf" (CLPP) method. This paper compares 1 year production results from 12 vertical wells in Reeves County, Texas completed with OHMS systems and 56 offset wells completed with the CLPP method. The system details, fracture methods used, as well as the cost and operational differences are discussed.
By comparing these two methods, this paper highlights OHMS as a long-term solution for operators completing vertical wells in stacked pay. The production, operation and cost comparisons of the two completion methods will provide theoretical and practical arguments to assist in designing a completion. The results of this study contribute to the technical conversation of how to economically produce a vertical well.
Multiphase Flow and Reactive Transport at the Pore Scale Using Lattice-Boltzmann Computer Simulations
Authors: Boek Edo S. , Zacharoudiou Ioannis , Gray Farrel , Shah Saurabh M. , Crawshaw John P. , Yang Jianhui 
Published: October 2014

Abstract
We describe the recent development of lattice-Boltzmann (LB) and particle tracing computer simulations to study flow and reactive transport in porous media. First, we have extended our codes to measure both flow and solute transport from LB calculations directly on pore space images obtained from micro-CT scanning. We consider rocks with increasing degree of heterogeneity: a bead pack, Bentheimer sandstone and Portland carbonate. A novel scheme is proposed to predict probability distributions for molecular displacements using the LB method to calculate both the flow field and solute dispersion. We find excellent agreement with PFG-NMR experiments and quantify the degree of heterogeneity by integrating over the stagnant peaks in the propagator distributions. Second, we validate our LB model for multi-phase flow by calculating capillary filling and capillary pressure in model porous media. Then we extend our models to realistic 3D pore space images and observe the calculated capillary pressure curve in Bentheimer sandstone to be in agreement with experiment. A new process based algorithm is introduced to determine the distribution of wetting and non-wetting phases in the pore space, as a starting point for relative permeability calculations. The Bentheimer relative permeability curves for both drainage and imbibtion are found to be in good agreement with experimental data. These LB simulations can be used for the prediction of multi-phase flow properties in pore space images; as potential element of Special Core AnaLysis (SCAL); and for Enhanced Oil Recovery (EOR) operations. Third, we introduce a GPU algorithm for large scale LB calculations, offering greatly enhanced computing performance in comparison with CPU calculations. Finally, we propose a new hybrid method to calculate reactive transport on pore space images. First, we calculate the flow field using LB and initialise tracer particles in the porous medium. Then we carry out particle advection using a 2nd order predictor-corrector scheme, particle diffusion using a random walk followed by reaction. We simulate the dissolution of a sphere under quiescent conditions in good agreement with the analytical solution. Then we calculate the dissolution of a cylinder in channel flow and observe preliminary agreement with experimental observations. This opens the way to calculating the dissolution of pore space images in direct comparison with micro-CT imaging experiments, for matrix acidizing and CCS operations. It is concluded that the LB method is a powerful tool for calculating flow and reactive transport directly on rock pore space images.
The Effect of Changing Fracture Compliance on Pressure Transient Behavior During Diagnostic Fracture Injection Tests
Authors: McClure Mark W. , Blyton Christopher A. , Jung Hojung , Sharma Mukul M. 
Published: October 2014

Abstract
Diagnostic Fracture Injection Tests (DFIT) are commonly interpreted with G-function derivative plots. In these plots, an upward deviation from linearity is generally attributed to fracture height recession or transverse storage. This interpretation neglects changing fracture compliance during closure. Results presented in this study show that in low permeability formations, an upward deviation of the G-function plot G*dP/dG is caused by a sharp reduction in fracture compliance due to closure. It is not necessary to invoke more complicated explanations such as height recession or transverse storage. The specific shape of the G*dP/dG curve is controlled by factors that affect fracture compliance before and after closure. These factors include the fracture height, fracture stiffness, and the residual aperture (which is affected by the microscopic and macroscopic roughness of the created hydraulic fracture). Wellbore storage broadens the post-closure peak in the G*dP/dG curve. A curve of G*dP/dG that constantly increases during the shut-in period may be caused by wellbore storage, rather than fracture tip extension. In higher permeability formations (with non-zero wellbore storage), the effect of fracture compliance is less important. As a result, changing fracture compliance during closure does not have a significant effect on the pressure transient plots, and closure decreases the rate of pressure decline because it reduces the rate at which fluid can leak off into the matrix. In all cases, as long as a single planar fracture has formed, the best pick for the minimum principal stress is at the deviation from linearity on the G*dP/dG plot, whether or not this departure is concave up or concave down. Closure picks via a tangent to near the peak in G*dP/dG (as is commonly performed) may significantly underestimate the minimum principal stress. These picks should be confirmed with other measurements, such as a subsequent injection period or a pump-in flow-back test. The fact that an extremely sharp upward trend in G*dP/dG is generally not observed in DFIT tests suggests that the actual geometry of the created fracture is rougher and more complex than is typically assumed by standard models.
Modeling Flow in Nanoporous, Membrane Reservoirs and Interpretation of Coupled Fluxes
Authors: Geren F. , Firincioglu T. , Karacaer C. , Ozkan E. , Ozgen C. 
Published: October 2014

Abstract
The average pore size in unconventional, tight-oil reservoirs is estimated to be less than 100 nm. At this pore size, Darcy flow is no longer the dominating flow mechanism and a combination of diffusive flows determines the flow characteristics. Concentration driven self-diffusion has been well known and included in the flow and transport models in porous media. However, when the sizes of the pores and pore-throats decrease down to the size of the hydrocarbon molecules, the porous medium acts like a semi-permeable membrane, and the size of the pore openings dictates the direction of transport between adjacent pores. Accordingly, characterization of flow and transport in tight unconventional plays requires understanding of their membrane properties. This paper first highlights the membrane properties of nanoporous, unconventional reservoirs and then discusses how filtration effects can be incorporated into the models of transport in nanoporous media within the coupled flux concept. The effect of filtration on black-oil simulation data is also demonstrated.
A New Mechanism of Formation Damage in Sandstone Matrix Acidizing Caused by Apatite; A Phosphate Cementing Material
Authors: Sakipour A. , Nasr-El-Din H. A. 
Published: October 2014

Abstract
Mineralogy is a key controlling factor in sandstone matrix acidizing treatments. Quartz, feldspars, calcite, dolomite, and different cementing materials are present in sandstone formations. It is crucial to be aware of the mineralogy in order to design acid treatments. Authigenic apatite, (Ca5(PO4)3(OH, F, Cl)2), is a cementing material in fluvial sandstone formations. If apatite is present in the formation, it will cause precipitation during matrix acidizing. The objective of this paper is to discuss a new mechanism of formation damage caused by apatite during matrix acidizing.
Laboratory experiments were conducted on sandstone cores at 140 and 300°F. Different cores with different mineralogy were selected to investigate the effect of apatite on the results of the acid treatment. Scanning Electron Microscopy (SEM) and Energy-Dispersive X-ray Spectroscopy (EDS) were used to analyze the mineralogy of the cores and to confirm the presence of phosphorous in the core samples. Cores were first damaged using fresh water, then preflush (formic-HCl) and organic mud acid (formic-HF) were employed to remove the damage. The initial and final permeability of the core was measured to investigate the result of the acid treatment. Core effluent samples were collected during each experiment for further analysis. Inductively Coupled Plasma (ICP) was utilized to determine the concentration of key cations in the core effluent samples. The SEM/EDS techniques were used to identify the precipitation in the core effluent samples.
This study showed that the presence of phosphorous in the core samples caused more damage after acid treatment. The presence of phosphorous caused precipitation. The SEM/EDS tests detected phosphorous in the core sample. However, it was not detected in all spots of the core that were tested. This indicates that the phosphorous was not distributed homogenously throughout the cores. The analysis of the precipitation in the core effluent samples indicated that the presence of phosphorous in the core caused the precipitation of iron(III) phosphate (FePO4) and aluminum phosphate (AlPO4). The precipitation occurred in samples where the pH was greater than 4. In addition, the precipitation occurred at both 140 and 300°F. Conducting experiments on the cores that did not contain phosphorus resulted in no precipitation in the core effluent samples. The samples were clean and transparent. The permeability measurements confirmed that the precipitation in the core effluent samples affected the results of the matrix acidizing and caused damage. This paper provides detailed evidence of a new mechanism of formation damage due to the presence of apatite as a cementing material.
Frictional Pressure Losses of Slurries in Straight and Coiled Tubing – Part I: Model Statistical Analysis
Authors: Shaqlaih Ali S. , Kamel Ahmed H. 
Published: October 2014

Abstract
Hydraulic fracturing has increased immensely in recent years. An accurate prediction of frictional pressure losses of fracturing slurries is crucial for successful treatment and to avoid premature screen-out or even treatment failure. Scarce data and lack of theoretical basis of slurry flow, especially in coiled tubing has led to very limited number of correlations that are available to predict slurry frictional pressure losses. Yet, the accuracy of the available correlations is still questionable.
The current paper presents a statistical comparative analysis of the available frictional pressure losses correlations for slurry flow in straight and coiled tubing employing the recently introduced math modeling technique that gives weight for the models known as Akaike information criterion, AIC. With the help of AIC, the authors evaluated the available correlations to examine their accuracy. The results show that none of the available correlations can accurately predict friction pressure losses of slurries. The correlations show some reasonable accuracy within a very limited data range. However, they fail outside this range indicative of their poor applicability. AIC shows how much information is lost when using these correlations which can lead to erroneous results, and even job failure. This fact keeps the gates widely opened for more in-depth experimental, analytical, and theoretical analysis for better understanding of flow behavior of fracturing slurries aiming at developing a more realistic correlation to predict their frictional pressure losses. This paper represents the authors' first step toward developing such correlation, with the application of information theory and AIC.
Understanding Multi-Fractured Horizontal Marcellus Completions
Authors: Shelley Robert , Nejad Amir , Guliyev Nijat , Raleigh Michael , Matz David 
Published: October 2014

Abstract
This project was undertaken to evaluate well potential and completion effectiveness for hydraulically fractured horizontal Marcellus completions located in Susquehanna County, Pennsylvania. This paper summarizes a study of the response of the Marcellus shale to hydraulic fractures and identifies performance drivers. How effective are these completions? How would these wells produce if they were completed and fraced differently? What are the primary controllable production drivers? How significant is geology and reservoir characteristics on well production? This paper attempts to answer such questions. Identification of major performance drivers becomes important in the design and optimization of new completions. They are not just important in enhancing production response and ultimate recoverable reserves but also prove to be important economic factors in new completion design.
This study employs neural network (ANN) modeling techniques to develop a predictive model to identify performance drivers and evaluate completion effectiveness. Sensitivities performed on the predictive ANN model developed for this project, indicate that well to well variation in reservoir quality and geology has a dominate effect on Marcellus production. Issues such as fracture spacing, frac volume, perforation distribution, proppant amount and fluid volume also affect well production. A summary of completion and frac methodology for wells in this database and a ranking of controllable (Completion and Frac) and non-controllable (Reservoir and Geology) parameters that effect Marcellus production are included. This information will be useful to stake holders interested in identifying reservoir, completion and frac parameters affecting production from the Marcellus and other analogous shale.
Uncertainty Assessment of Stimulation Design—Bakken Case Study
Authors: Jabbari H. , Ostadhassan M. , Khavanin M. , Lentz N. , Johnson S. 
Published: October 2014

Abstract
Numerical simulation models that are used for well stimulation planning are usually complex and are prone to error. These models have many factors that generally contain uncertainty which, in turn, lead to uncertainty in the model outputs. Uncertainty assessment (UA) can describe such uncertainties in the modeling results. It is always important to the future development plans that uncertainty be properly assessed.
This paper presents an approach to the uncertainty assessment of simulation models used for the design optimization of hydraulic fracturing. The use of numerical simulation in petroleum engineering, and the presence of uncertainty in all aspects of design and modeling, may lead to questions such as: What confidence do we have in model results? What are the limits in terms of applicability of model results? Uncertainty assessment together with sensitivity analysis can provide the answers to such questions. The Monte Carlo simulation is employed for implementing such analyses that includes repeated random sampling from input probability distributions.
In the assessment of uncertainty conducted for the Bakken case study discussed in this paper, the following seven-step procedure is implemented: describing assessment goals, describing assumptions and constraints, describing parameters and outputs, classifying factor uncertainty, conducting the sensitivity analysis, conducting the uncertainty assessment, and presenting the results with probability curves. The main goal of this study is to present the use of probabilistic modeling for assessing the uncertainties in the simulation of hydraulic fracturing and reservoir performance. Such probabilistic modeling can also help us to develop proxy models for approximating outputs at un-simulated points and to demonstrate the simulation results with probability distribution curves.
An Economic Evaluation on the Re-fracturing Treatment of the U.S. Shale Gas Resources
Authors: Eshkalak Mohammad O. , Aybar Umut , Sepehrnoori Kamy 
Published: October 2014

Abstract
We investigate the economic feasibility of the re-fracturing treatment of horizontal wells producing gas from unconventional reservoirs. As a result of advancements in horizontal completions and hydraulic fracturing, the U.S. has been able to economically develop several decades of worth of natural gas from shale deposits. However, a considerable concern has risen on the economic viability of shale gas development with the reasons associated to the very fast production declines as well as recent down-turns of natural gas prices beside the raise in additional costs of new technologies. Therefore, an economic analysis required to investigate the profitability of the secondary enhanced gas recovery method, re-fracturing treatment of unconventional gas resources within the U.S.
Net present value (NPV) of cash flows and internal rate of return (IRR) are calculated for different assumed gas prices considering 20 years of natural gas production from a typical unconventional reservoir. A systematic comparison is made for three scenarios, 1) re-fracturing vs. no re-fracturing (the base case scenario) 2) combination of re-fracturing and drilling new well; and 3) time-dependent re-fracturing treatment. This paper incorporated the cost of re-fracturing treatment, the cost of drilling a new horizontal well, the water treatment cost, as well as the current and future price of natural gas in the model. Findings of this work can be used to optimally develop the U.S. shale gas assets. Moreover, operators can have access to an assessment to ensure the economic success of their unconventional horizontal wells in their future re-fracturing treatments.