bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach for Simultaneous Estimation of Relative Permeability and Capillary Pressure from Coreflood Experiments
Authors: Jahanbakhsh Amir , Sohrabi Mehran 
Published: September 2015

Abstract
Relative permeability (kr) and capillary pressure (Pc) are the most important flow functions in numerical simulation of multiphase flow in porous media. The values of kr and Pc are conventionally measured in separate experiments often with different methods. kr curves are usually measured by performing corefloods in the laboratory using two methods namely, ‘steady state’ and ‘unsteady state’ experiments. Pc is normally measured by mercury porosimetry, the porous plate method or by centrifuge method. The drawback of determining relative permeability and capillary pressure separately is that they may not be consistent with each other and the measured Pc does not correspond to the kr which is measured from dynamic flow system. Therefore, simultaneous determination of Pc and kr for a given system would be preferred. History matching techniques have been applied in the past to estimate relative permeability and capillary pressure simultaneously from unsteady state core flood experiments. In previous attempts, two independent functions were used to generate these two flow functions in the process of the history matching. To reduce the associated non-uniqueness problem of history matching, some in-situ measurements such as saturation and pressure profiles may be included in the history matching data but this information is rarely available.
The objective of this study is to honor a known relationship between the core relative permeability and the Pc curve and improve the optimization process and the accuracy of the estimated Pc and kr. Making the kr function dependent on the Pc in the history matching process will reduce the number of tuning parameters and is expected to reduce the uncertainty associated with the history matching process. A Purcell type model, which is based on the physics of fluid displacement, is used as the basis for linking the permeability (or relative permeability) to Pc.
Adsorption Enhanced Transport of Hydrocarbons in Organic Nanopores
Authors: Riewchotisakul Sansarng , Akkutlu I. Yucel 
Published: September 2015

Abstract
In this paper we present the results of steady state methane flow in carbon tubes under reservoir conditions using nonequilibrium molecular dynamics simulations, which show that the organic capillaries in resource shales contain a mobile adsorbed phase. This mobility leads to a significant shift up in the flow velocity profile of the fluid across the diameter of the tube. The contribution of the adsorbed phase to transport is significant in capillaries with size less than 20 nm. A new permeability model is proposed which considers these observations. We use the bundle of capillaries approach and estimate that the permeability correction for organic pores of Marcellus shale has more than 50 % increase. Further research is required to consider the transport of the other hydrocarbons and their mixtures.
Miscible CO2 Water-Alternating-Gas (CO2-WAG) Injection in a Tight Oil Formation
Authors: Han Longyu , Gu Yongan 
Published: September 2015

Abstract
In this paper, miscible CO2 water-alternating-gas (CO2-WAG) injection in the Bakken formation is experimentally studied and optimized. First, tight sandstone reservoir rock samples from the Bakken formation are characterized. Second, the saturation pressure, oil-swelling factor, CO2 solubility, CO2-saturated Bakken light crude oil density and viscosity are measured. Third, the vanishing interfacial tension (VIT) technique is applied to determine the minimum miscibility pressure (MMP) of the Bakken light crude oil and CO2 at the actual reservoir temperature. Last, a total of nine coreflood tests are conducted through respective waterflooding, continuous miscible CO2 flooding, and miscible CO2-WAG injection. In the miscible CO2-WAG injection, different WAG slug sizes of 0.125, 0.250, and 0.500 pore volume (PV) and different WAG slug ratios of 2:1, 1:1, and 1:2 are used to study their specific effects on the oil recovery factor (RF) in the Bakken formation. In addition, miscible CO2 gas-alternating-water (CO2-GAW) injection is also tested as an opposite fluid injection sequence of the miscible CO2-WAG injection. It is found that in general, CO2 enhanced oil recovery (CO2-EOR) method is capable of mobilizing the light crude oil in the Bakken tight core plugs under the miscible condition. The miscible CO2-WAG injection has the highest oil RF (78.8% in Test #3), in comparison with waterflooding (43.2% in Test #1), continuous miscible CO2 flooding (63.4% in Test #2), and miscible CO2-GAW injection (66.2% in Test #8). Furthermore, using a smaller WAG slug size of CO2-WAG injection leads to a higher oil RF. The optimum WAG slug ratio is approximately 1:1 for the Bakken tight oil formation. More than 60% of the light crude oil is produced in the first two cycles of the miscible CO2-WAG injection. The CO2 consumption in the optimum miscible CO2-WAG injection is much less than that in the continuous miscible CO2 flooding.
An Integrated Approach to Optimize Production in Marcellus Shale Gas Reservoirs
Authors: Yu Wei , Wu Kan , Sepehrnoori Kamy 
Published: September 2015

Abstract
With the development of shale gas reservoirs, various fracture propagation models have been developed to predict hydraulic fracture geometry by considering the stress shadow effects. Also, many researchers have been working on development of various production-simulation approaches to simulate production from the complex fracture geometries. The objective of this study is to combine the fracture propagation modeling and reservoir simulation to optimize production in shale gas reservoirs. First, we have developed a semi-analytical model to simulate shale gas production from the complex non-planar fracture geometry with varying fracture width and fracture permeability along fracture length. The important gas transport mechanisms including gas slippage, gas diffusion, and gas desorption are considered. Second, we integrate the semi-analytical model with a three-dimensional fracture propagation model, which fully couples elastic deformation of the rock and fluid flow to simulate complex hydraulic fracture propagation, to optimize fracture treatment design in Marcellus shale gas reservoirs.
Specifically, the fracture propagation model is utilized to predict the more-realistic non-planar fracture geometry with varying fracture width and fracture permeability along fracture length. In this study, the effect of varying number of perforation clusters within a given stage ranging from 2 to 5 on the fracture propagation was investigated. Three values of stage spacing were considered including 100 ft, 200 ft, and 300 ft. After predicting the non-planar fracture geometry, the semi-analytical model is employed to simulate production from such fracture geometries. According to the well productivity, the optimal number of clusters per stage for varying stage spacing is discussed and determined. In addition, we compared the well performance with the optimal number of perforation clusters for the stage spacing of 100 ft, 200 ft, and 300 ft under a given horizontal well length of 2,500 ft. Furthermore, we used the integrated approach to analyze a well performance from Marcellus shale gas reservoirs. Through the field case study, the more-realistic non-planar fracture geometry was quantified. Also, the difference between the non-planar fracture geometry and ideal planar fracture geometry with equal fracture width and fracture half-length was compared. Finally, the optimal fracture treatment design for the field well development was recommended. This work can provide new insights into optimization of number of perforation clusters per stage within a given fracture stage and a better understanding of the non-planar fracture geometry in shale gas reservoirs.
Phase Envelope Calculations for Reservoir Fluids in the Presence of Capillary Pressure
Authors: Sandoval Diego , Yan Wei , Michelsen Michael L. , Stenby Erling H. 
Published: September 2015

Abstract
Reservoir fluids are multicomponent mixtures in confined spaces, where the role of capillary force becomes important when the average pore size is on the order of tens of nanometers, such as in tight rocks and shale. We present an algorithm for calculating the phase envelope of multicomponent mixtures in the presence of capillary pressure. The algorithm uses a rigorous equation of state (EoS) model, such as the Soave-Redlich-Kwong EoS, for phase equilibrium, and the Young-Lapace equation for the capillary pressure. The interfacial tension is calculated using a parachor based model. A full Newton method is employed to solve the governing equations of the vapor-liquid equilibria coupled with the capillary pressure equation. For a stable and automatic construction of the phase envelope sensitivity analysis is used in each step. The developed algorithm can reliably generate not just the bubble and dew point curves but also other quality lines with vapor fractions between 0 and 1. The algorithm has been used to calculate the phase envelopes of binary, multicomponent and reservoir fluid systems for pore radius from 10 to 50 nm. The presence of capillary pressure changes the saturation pressures in the whole phase envelope except at the critical point. The bubble point curve shows a negative change while the dew point curve shows positive and negative changes in the upper dew point branch and the lower dew point branch, respectively. In particular, the cricondentherm is also shifted towards a higher temperature. The change in the phase envelope becomes larger as the pore size decreases. The effects of composition and gas oil ratios are also discussed.
New Methods for Interpretation of NMR Measurements Acquired in Spatially Heterogeneous Rocks
Authors: Medellin David , Ravi Vivek R , Torres-Verdín Carlos 
Published: September 2015

Abstract
The interpretation of the Nuclear Magnetic Resonance (NMR) T2 distribution as a pore size distribution assumes homogeneous surface relaxivity, single-phase fluid saturation, and the absence of diffusion of spins across pores. Although these assumptions are true for homogeneous formations with single-phase fluid saturation, they do not hold for heterogeneous formations such as deep-water carbonates, where laminations, vugs, and a mixed solid composition result in non-uniform values of surface relaxivity and diffusion of spins across pores. These spatial heterogeneities in rock formations render the interpretation of NMR logs challenging and non-conclusive. Furthermore, methods to estimate permeability, such as the Timur-Coates and the Schlumberger-Doll-Research (SDR) method assume a single relaxivity value and, thus, cannot be applied to NMR T2 data from formations with non-uniform relaxivity values.
NMR mixing laws describe how to combine data acquired from homogeneous components, thus enabling us to predict the data resulting from a mixture of those homogeneous components. This paper develops a new method to interpret NMR distributions originating from highly heterogeneous formations using mixing laws for T2, T1 — T2, and T2 — D NMR data. This new method allows us to extract the magnetization decay of each homogeneous component from the total magnetization decay of the heterogeneous formation. Decomposing the magnetization decay allows us to estimate the T2 distributions for each individual rock component and use them to obtain improved estimations of petrophysical quantities of interest such as porosity, pore size distribution, and the intrinsic permeability of each homogeneous component.
We show how to use the linear mixing laws in laminated formations to extract the T2 distributions from each individual component of a heterogeneous rock and how to obtain an improved estimation of the permeability of the formation.
Bayesian Style History Matching: Another Way to Under-Estimate Forecast Uncertainty?
Authors: Vink Jeroen C. , Gao Guohua , Chen Chaohui 
Published: September 2015

Abstract
Current theoretical formulations of assisted history matching (AHM) problems within the Bayesian framework, e.g., ensemble Kalman filter (EnKF) and randomized maximum likelihood (RML), are typically based on the assumption that simulation models can accurately reproduce field data within the measurement error. However, this assumption does not hold for AHM problems of real assets. This paper critically investigates the impact of using realistic, inaccurate simulation models. In particular it demonstrates the risk of underestimating uncertainty, when conditioning real-life models to large numbers of field data. Even though it is well-known, that model error and under-modeling impacts Bayesian methods, the practical effect that uncertainty may be severely underestimated, simply by using all available data is not well appreciated. Besides highlighting this effect, also a mitigation strategy to counteract this problem will be proposed and shown to be effective for the analytical toy model as well as for the real field case used as tests in this paper.
After briefly reviewing the Bayesian method and its underlying assumptions, limitations of AHM approaches within the Bayesian framework are analyzed using a simple analytical model in which forecast uncertainty can be computed both with and without constraints due to historic data. In particular the model can be used to illustrate the impact of using an inaccurate, or incomplete, simulation model. The observations from this analytical work can then be generalized to real-life workflows that are currently implemented in many commercial and proprietary tools. To mitigate the observed problem, a fairly simple but effective modification of the AHM workflow is proposed and tested on the analytical test case.
The same mitigation procedure is then also applied to improve uncertainty quantification of production forecasts using a real asset model. In order to see if the proposed workflow indeed leads to a more credible uncertainty assessment for forecast results, a specific realization of the asset model is used to generate synthetic production data. The model used for history matching and uncertainty quantification uses a different geological realization and hence can never reproduce the production results (which are assumed to have negligible noise). Also in this realistic setting, it is shown that forecasts easily can be under-estimated when large numbers of data are used to constrain forecast uncertainty in an imperfect model with accurate data. This undesired effect comes out as the flip-side of the attractive property of Bayesian methods that model parameters can be inferred with increased accuracy if the number of data is increased in a perfect model with noisy data.
Three-Phase Relative Permeability in Consolidated Media
Authors: Kianinejad Amir , Chen Xiongyu , DiCarlo David A. 
Published: September 2015

Abstract
Relative permeability of oil in water-wet rocks in three-phase systems depends on water saturation in addition to oil saturation. This dependency results in infinite possibilities of combinations of phase saturations in three-phase space, making measurements of three-phase relative permeability difficult and time consuming. Therefore, measurements of changes in three-phase relative permeability in three-phase space are scarce. On the other hand, the existing three-phase relative permeability models for predicting these changes (e. g. hysteresis) are usually complicated and require several parameters. In this work, we measure three-phase oil relative permeability curves along different saturation paths by developing a gravity drainage technique that works in consolidated sandstone. The experiments consist of measuring in-situ saturations along a 2-ft long vertical Berea sandstone core at different times using computed tomography (CT) technique during gravity drainage experiments, along three saturation paths over three-phase space. We then obtain three-phase oil relative permeability directly from the transient in-situ saturations measured during each experiment. Our data show that at the same oil saturation, the three- phase oil relative permeability varies significantly depending on the saturation path in three-phase space. From these measurements we use standard and simple Corey relative permeability model to fit the results. We find that each saturation path exhibits a different residual oil saturation, and that the Corey model matches the data well once the residual oil saturation is given correctly for each saturation path, while keeping all the other parameters constant. Our results suggest that, contrary to previous results, three-phase oil relative permeability in water-wet media is only a function of oil saturation, if the residual oil saturation changes are accounted for accordingly. In other words, we conclude that the key to correctly model three-phase relative permeability is the use of correct residual saturations for each saturation path (history).
Chemical EOR for Offshore Platforms Using a Novel Chemical Gradient Design
Authors: Trine Eric , Suniga Pearson , Fortenberry Robert 
Published: September 2015

Abstract
Developing robust, low cost surfactant-polymer (SP) solutions for use in offshore oilfields has historically proven difficult. The objective of this study was to develop and test a practical EOR process for injecting surfactant-polymer mixtures in seawater followed by a polymer drive in seawater – we call this approach the chemical gradient. The main target for this approach is offshore applications for platforms with space and facility limitations where alternative sources of injection brine are not available or very limited, making it difficult to use a conventional salinity gradient design. A proposed strategy for modeling the chemical gradient is also included in this work.
The conventional way to design a surfactant-polymer (SP) flood is to use a salinity gradient. This is the simplest, most efficient and most robust design approach. This means the surfactant-polymer slug is injected at its optimum salinity and then followed by a polymer drive at a lower salinity, usually about 70% of the slug salinity. This can be done by blending brines with different salinities, desalinating or softening an available injection brine and other means. However, sometimes none of these alternatives are practical using an existing offshore platform.
We designed a high-performance SP flood requiring only seawater as the injection brine. We added a very small amount of a hydrophilic surfactant to the polymer drive following the surfactant/polymer slug to create a chemical gradient equivalent to a salinity gradient to improve robostness. We tested the design in an outcrop coreflood experiment and observed excellent performance including high oil recovery and propagation of the chemicals in a sharp bank.
Assessing the Consistency of Measurements and Models for the Kinetics of In Situ Combustion
Authors: Cinar Murat , Kovscek Anthony R. 
Published: September 2015

Abstract
One method to access unconventional, heavy-oil and natural bitumen resources is to apply in situ combustion (ISC) to oxidize in place a small fraction of the hydrocarbon thereby providing heat to reduce oil viscosity and pressure that enhances recovery. ISC is also attractive because it provides the opportunity to upgrade oil in-situ by increasing the API gravity and decreasing, for instance, sulfur content. The complex nature of petroleum as a multi-component mixture and the multi-step character of oxidation reactions complicates substantially the kinetic analysis of crude-oil oxidation. Isoconversional techniques provide model-free methods for estimating activation energy and naturally deconvolve multi-step reactions. The isoconversional fingerprint is, essentially, the profile of activation energy as a function of temperature (from low to high) of the sample. As such, isoconversional methods are also useful as a screening tool to categorize the burning characteristics of different oils. In the literature there are substantially different kinetic models for the representation of reactions during in situ combustion. Some models feature multistep reactions in series whereas other models combine series and parallel reaction steps. Interestingly, there is no study comparing these models with each other as well as consistent experimental data. In this study, the performance of different models proposed in the literature and a new model is tested using kinetic cell simulations and compared to new experimental data. As the basis of the comparison, the isoconversional fingerprints associated with the models existing in the literature are compared. Results indicate that most of the models proposed are unable to reproduce the typical isoconversional fingerprint measured for crude-oil combustion. This lack of agreement explains, in part, the poor predictability of reactive transport simulations of ISC. Importantly, this work illustrates a methodology for assessing the consistency of a kinetic model with experimental data and identifies physically consistent models.
Study of Kerogen Maturity using Fourier Transform Infrared Spectroscopy (FTIR) and Thermogravimetric Analysis (TGA)
Authors: Dang S. T. , Sondergeld C. H. , Rai C. S. 
Published: September 2015

Abstract
Maturity of kerogen in shale governs the productivity of a shale formation. Produced fluids are strongly dependent upon organic type (governed by depositional fossils and environment) and thermal history. Different maturity measurement methods (vitrinite reflectance, Rock Evaluation, biomarkers) have been studied, but failed to precisely determine maturity levacross all levels of maturity. Vitrinite reflectance (%Ro) measurement cannot be applied for marine shales and pre-Silurian shales, which do not include plant materials. Tmax (main maturity indicator from Rock Evaluation pyrolysis) measurement is questionable for mature and post-mature samples. Most of biomarkers become useless when maturity level reaches condensate window. In this study, we introduce using Fourier Transmission Infrared Spectroscopy (FTIR) and Thermogravimetric (TGA) for both qualitative and quantitative assessment on organic maturity in shale. Separation of organic matter or identification macerals is not required by either technique; they are quick and objective tests providing two IR-based maturity indices. The first index, CH2/CH3, (from FTIR alone) shows good sensitivity up to the end of the condensate window. CH2/CH3 index decreases with more mature samples. The following CH2/CH3 values are used to define the immature (&gt;1.63 ± 0.22), oil window (1.63 ± 0.22 to 1.3 ± 0.25), wet gas window (1.3 ± 0.25 to 1.13±0.05), and dry gas window (&lt;1.13± 0.05). Whereas, the second index, Tmethane, (from TGA and FTIR) can help to extend the maturity scale beyond the condensate window; this overcomes the main limitations of Rock Evaluation and biomarker analyses. The index increases with maturity. The result shows Tmethane yields a good correlation with vitrinite reflectance, Tmethane = 83.6%Ro + 497.5 (R2 = 0.89.)