bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stochastic Modeling of a Fracture Network in a Hydraulically Fractured Shale-Gas Reservoir
Authors: Mhiri A. , Blasingame T. A. , Moridis G. J. 
Published: September 2015

Abstract
This study introduces a novel approach to model the hydraulic fractures in a shale reservoir using a common stochastic method called “random-walk.” The goal of this work is to capture part of the “complexity” of a fracture/fracture network that has been generated by a hydraulic fracturing treatment and to attempt to characterize this fracture network using reservoir performance signatures.
The steps involved in this work are:
Stochastic generation of a “random-walk” fracture pattern constructed as a scaled numerical model. Assessment of the “random-walk” fracture using sensitivity analyses which consider the following elements: — The tortuosity (i.e., the actual length to ideal length ratio) — The tendency to branch (or split). — The number of branching stages — the number of branches was held constant for a given set of cases. Comparison of the mass rate and beta mass rate-derivative performance of the various “random-walk” fracture cases compared to the “standard” model of a planar fracture.
The primary results of this work are:
Generation of pressure distributions (maps) at given times (i.e., “time slices”) to qualitatively assess each complex-pattern during transient production. The pressure distribution figures (i.e., maps) are used to qualitatively determine the presence of fracture interference(s) and to identify a time interval where those interferences occur. Creation of a graphical correlation of reservoir performance in terms of cumulative recovery as a function of the fracture volume and “fracture complexity” (i.e., the number of branches). Creation of an empirical correlation between the number of branches in a given fracture pattern and the value of the mass rate beta-derivative during transient flow (we observed that the mass rate beta-derivative is essentially constant during transient flow regardless of the fracture network configuration, as such this constant value of the mass rate beta-derivative was selected for correlation).
This work provides an alternative description of hydraulic fractures in unconventional shale-gas reservoirs which, in concept, captures the complexity of the hydraulic fracture as a stochastic fracture network.
Early-time rate performance is believed to be an indicator of the geometry of the hydraulic fracture pattern. A fracture with a higher level of “complexity” yields higher values of mass rate beta-derivative when the fractures components are interfering with each other. Therefore, mass rate curves could be used as a diagnostic tool that helps the identification of the fracture geometric features.
Modeling Impact of Geochemical Reactions on a Real Reservoir Fluid Mixture During CO2 EOR
Authors: Venkatraman Ashwin , Dindoruk Birol , Elshahawi Hani , Lake Larry W. , Johns Russell T. 
Published: September 2015

Abstract
CO2injection in oil reservoirs has the dual benefit of enhancing oil recovery from declining reservoirs as well as sequestering a greenhouse gas to combat climate change. CO2injected in carbonate reservoirs, such as those found in the Middle East, can react with ions present in the brine and the solid calcite in the carbonate rocks. These geochemical reactions impact the overall mole numbers and in some extreme cases, even the number of phases at equilibrium impacting oil recovery predictions obtained from compositional simulations. Hence, it is important to study the impact of geochemical reactions on a real reservoir fluid mixture during CO2injection. In this study, the Gibbs free energy function is utilized to integrate phase behavior computations and geochemical reactions to find equilibrium compositions. The Gibbs free energy minimization method using elemental balance constraint is used to obtain equilibrium compositions arising at phase and chemical equilibrium. The solid phase is assumed to be calcite, the hydrocarbon phases are characterized using the Peng-Robinson (PR) Equation of State (EOS), and the aqueous phase components are described using the Pitzer activity coefficient model. The binary interaction parameters for the EOS and the activity coefficient model are obtained using experimental data.
The impact of the changes in phase behavior of a real reservoir fluid with 22 components is presented in this manuscript. We observe that the changes in phase behavior of the resulting reservoir fluid mixture in the presence of geochemical reactions depend on two factors: 1) the volume ratio (and hence molar ratio) of the aqueous phase to the hydrocarbon phase and 2) the salinity (and composition) of the brine. These changes represent a maximum impact of geochemical reactions since all reactions are assumed to be at equilibrium. This approach can be adapted to any reservoir brine and hydrocarbon as long as the initial formation water composition and their Gibbs free energy at standard states are known. The resultant model can be integrated into any reservoir simulator as integrated algorithms can be used for minimizing the Gibbs free energy function of the entire system.
Dynamics of Fracture-matrix Coupling during Shale Gas Production: Pore Compressibility and Molecular Transport Effects
Authors: Wasaki Asana , Akkutlu I. Yucel 
Published: September 2015

Abstract
Much work has been done to demonstrate an economical impact of various fluid transport mechanisms on the long term behavior of shale gas production. These studies were elementary level and focused on identifying a dominant mechanism of production. They did not consider, however, the interaction of the fractures with the shale matrices in detail. In the near wellbore environment the fracture is the crucial component of transport, whereas the matrix is the place for storage. In this paper, using a new in-house reservoir flow simulator, we introduce the nature of this interaction and show that the transport in the tight matrix can be induced by carefully designing the well completions and by operating under the optimum production conditions.
The simulator accounts for a hydraulic fracture coupled to shale matrix with an anistropic apparent permeability field, which is stress-sensitive and includes the effects of molecular transport phenomena. The fracture has a dynamic conductivity with a simple nonlinear deformation rule reflecting proppant embedment effect on the conductivity. Using a sector model, we predict short-term cumulative production trends. The results indicate that design of horizontal wells with multiple fractures should take into account the geomechanical and diffusional resistances associated with the gas transport in the matrices. Further, in-series nature of the production indicates that changes in fracture conductivity beyond its threshold value has negligible effect on the production trends. Therefore, production optimization efforts should instead focus to considerations to improve the flow rates in the matrix.
Enhanced Oil Recovery in Liquid-Rich Shale Reservoirs: Laboratory to Field
Authors: Alharthy Najeeb , Teklu Tadesse , Kazemi Hossein , Graves Ramona , Hawthorne Steven , Braunberger Jason , Kurtoglu Basak 
Published: September 2015

Abstract
Production of tight oil from shale reservoirs in North America reduces oil imports and has better economics than natural gas. Consequently, there is a strong interest in oil production from Bakken, Eagle Ford, and Niobrara. However, oil recovery factor for Bakken remains low, which is about four to six percent of the oil in place. Even with this low oil recovery factor, Bakken recoverable reserves are estimated to be 7.4 billion barrels; thus, a large volume of oil will remain unrecovered. This low level of oil recovery was the motivation to investigate the feasibility of enhanced oil recovery (EOR) in liquid-rich shale reservoirs such as Bakken.
In this paper, we will present both laboratory and numerical modeling of EOR in Bakken cores using CO2, C1-C2 mixture, and N2. The laboratory experiments were conducted at the Energy and Environmental Research Center (EERC). The experiments recovered 90+ percent oil from several Middle Bakken cores and nearly 40 percent from Lower Bakken cores. To decipher the oil recovery mechanisms in the experiments, a numerical compositional model was constructed to match laboratory oil recovery results. We concluded that solvent injection mobilizes matrix oil by miscible mixing and solvent extraction in a narrow region near the fracture-matrix interface, thus promoting counter-current flow of oil from the matrix instead of oil displacement through the matrix. Specifically, compositional modeling results indicate that the main oil recovery mechanism is miscible oil extraction at the matrix-fracture interface region. However, the controlling factors include re-pressurization, oil swelling, viscosity and interfacial tension reduction, diffusion-advection mass transfer, and wettability alternation.
We scaled up laboratory results to field applications via a compositional numerical model. For field applications, we resorted to the huff-and-puff protocol to assess the EOR potential for a North Dakota Middle Bakken well. We concluded that long soak times yields only a small additional oil compared to short soak times, and re-injecting wet gas, composed of C1,C2, C3, and C4+, produces nearly as much oil as CO2 injection.
Improved NMR Logging Approach to Simultaneously Determine Porosity, T2 and T1
Authors: Coman Radu , Tietjen Holger , Thern Holger , Blanz Martin , Christensen Søren Amdi 
Published: September 2015

Abstract
The simultaneous measurement of T1 and apparent-T2 relaxation times of a movable fluid with a nuclear magnetic resonance (NMR) logging-while-drilling (LWD) tool significantly increases the robustness of measured porosity at elevated rates of penetration. A new processing method is the basis for improved NMR logging products including water saturation, permeability prediction, pore size distribution, and oil viscosity estimation.
Current NMR-LWD acquisition and processing methods treat T2 relaxation times and T1 relaxation times independently. NMR tools with high magnetic field gradients and tools powered with batteries are practically restricted to the T1 measurement, whereas tools with low magnetic field gradients powered by a mud-flow alternator usually run in an acquisition mode that provides only a T2 distribution. The processing method presented here simultaneously provides a full T2 distribution corrected for axial-motion effects (polarization effect and flow effect) as well as the T1 relaxation time of the movable fluid.
The method employs two T2 echo trains with various wait times and uses the amplitude ratio of the movable fluid to estimate the geometric mean of T1 for that fluid. The algorithm takes into account not only the polarization effect on the measured porosity caused by a finite wait time, but also the polarization effect caused by an elevated logging speed.
This new approach is especially useful for reservoirs with gas, vuggy porosity or light hydrocarbon where T1 of the movable fluid is large and the usual acquisition approach requires a correspondingly long wait time. By computing T1 with the presented approach, and by using it to correct for polarization effects, shorter polarization times can be employed, which can improve vertical resolution. Moreover, the polarization correction and the flow correction improve the accuracy of NMR-derived porosity and significantly expand the logging speed range for high-quality NMR-LWD applications. The advantages of the new method are proven by a log data example from a light hydrocarbon reservoir.
Development of a Mechanistic Numerical Simulator for Preformed Particle Gel Applications in Non-Crossflow Heterogeneous Reservoirs
Authors: Imqam Abdulmohsin , Goudarzi Ali , Delshad Mojdeh , Bai Baojun 
Published: September 2015

Abstract
Water channeling is caused by reservoir heterogeneities that lead to the development of high-permeability streaks. A recent interest in microgel treatment using preformed particle gels (PPGs) has drawn more attention to reducing excess water production, improving sweep efficiency, and enhancing macroscopic oil recovery. The objective of this paper is to gain an inclusive understanding of PPG transport mechanisms through heterogeneous reservoirs. A numerical simulator was developed to characterize the propagation of PPGs through given reservoir. The simulator was used to optimize the gel treatment design to enhance oil recovery from un-swept, low-permeability, and oil-rich zones. A novel core flooding experiment was conducted to validate the developed mechanistic models. The experimental results using heterogeneous permeability model without cross flow showed large incremental oil recovery from the low permeability sand pack after treatment with PPGs. The developed models were implemented into the gel transport reservoir simulator to aid in the design and to optimize the water control processes using PPGs. The results obtained from the simulator indicated a good match with core flooding experiment results. The sensitivity analysis showed incremental oil recovery was strongly dependent on the permeability contrast, PPG concentration, and PPG treatment size.
An Investigation on the Impact of Heterogeneity on Fluid Injectivity Loss during Water-Alternating-Gas Injection in Carbonate Formations
Authors: Saneifar Mehrnoosh , Heidari Zoya , Linroth Mark 
Published: September 2015

Abstract
Water-Alternating-Gas (WAG) injection technique has been widely applied to improve sweep efficiency of gas injections in depleted oil fields. However, injectivity abnormalities have been a limiting factor, adversely impacting the success and the economic feasibility of WAG projects. Heterogeneous distribution of petrophysical properties in carbonate formations are among parameters causing injectivity loss during WAG cycles. WAG injection reduces the effective fluid mobility in all rock classes, irrespective of their petrophysical properties and flow characteristics. Thus, a larger fraction of fluids flow into the rock classes of higher permeability, resulting in a poor frontal advancement in rock classes of lower permeability. This leads to reduced overall injectivity and loss of WAG operation efficiency. In this paper, we investigate and quantify the impact of spatial heterogeneity in a carbonate formation on injectivity loss during WAG injection.
We conduct automatic rock classification based on conventional well logs, using an unsupervised artificial neural network method, to characterize the rapid variation of petrophysical properties and mineralogy in a carbonate formation. We then apply a new heterogeneity coefficient to quantify the spatial distribution of rock classes. The introduced heterogeneity coefficient is validated using Principal Component and variogram analyses. The aforementioned technique was applied to ten wells of the SACROC unit, located in west Texas, subjected to WAG operation. Five of the selected wells in this field exhibited no injectivity abnormality, while the other five wells experienced unexpected low gas injectivity during CO2 injection and an apparent reduction in water injectivity during the follow-up brine injection. Rock classification generated three rock classes based on the distribution of porosity, permeability, pore types, and clay content. We quantified the magnitude of the spatial heterogeneity based on distribution of rock classes in all ten wells. We then investigated the impact of the heterogeneity on the injectivity loss during WAG injection by comparing the identified heterogeneity coefficients in all wells. The results showed that in the wells with WAG injectivity loss, the distribution of rock classes is approximately 30% more heterogeneous, compared to the wells with no injectivity loss. In the wells with injectivity loss, we also observed about 32% and 43% higher occurrence of rock classes 1 and 2, respectively, compared to the wells with no injectivity loss. An analysis of the formation spatial heterogeneity can be applied to improve selection of candidate wells for WAG injection and potential success of oil recovery projects.
Increasing Shale Gas Recovery through Thermal Stimulation: Analysis and an Experimental Study
Authors: Lin Yue , Wang HanYi , He Shuai , Nikolaou Michael 
Published: September 2015

Abstract
The Silurian Longmaxi shale gas play in the Jiaoshiba (JSB) structure in the southeast margin of the Sichuan Basin in China is studied to discuss the key factors that control the adsorption/desorption behavior of natural gas in shale formations. The rationale for this study is that understanding these factors can be helpful in shale gas stimulation designs that enhance recovery by combining hydraulic fracturing with thermally induced desorption of adsorbed shale gas.
The Jiaoshiba structure is a faulted anticline which experienced multiphase tectonic movement. The Longmaxi Formation has high thermal evolution degree with Ro more than 2.2%, and has a 35-45 meters thick high-quality shale (TOC &gt; 2%) in its lower part. The reservoir is overpressure with a pressure coefficient of 1.55, and shale gas production and pressure are stable. Experimental measurements have indicated that more than 65% of the total gas storage in the Jiaoshiba shales exists as an adsorbed phase. Modeling the adsorbed phase can impact the selection of stimulation techniques as well as production forecasts. Adsorption generally cannot be determined accurately from history matching production data alone. The laboratory testing of actual shale samples from reservoir cores is important for characterizing shale gas adsorption behavior.
Previous laboratory studies have reported data from measurements at single temperatures, and the measured data have been represented by Langmuir isotherms. However, the effect of temperature on adsorption has not been explored. In this work, a series of experiments were conducted to measure adsorption curves for shale samples at various temperatures and depths from the Jiaoshiba shales. We investigated the representation of adsorption behavior as a function of both temperature and pressure.
The pressure-temperature dependent gas adsorption behavior is described by Bi-Langmuir model by fitting the unknown adsorption characteristic parameters against laboratory experiment data at low temperature, the gas adsorption behavior at higher temperature can be predicted by extrapolation from the model. The predicted gas adsorption capacity agree well with our experiment data, which demonstrate this model's capability to predict gas adsorption capacity at reservoir temperature based on data measured at laboratory conditions.
The pressure and temperature sensitive gas adsorption behavior is incorporated into an unconventional reservoir simulator, to investigate how thermal stimulation can impact shale gas production and ultimate recovery from hydraulic fractured shale formations. The results indicates that thermal stimulation has the potential to enhance shale gas recovery significantly by altering shale gas adsorption/desorption behavior through the elevation of formation temperature.
Reducing Reservoir Uncertainty During Appraisal and Development - Novel Applications of a new Wireless Reservoir Monitoring Technology in Santos Basin Pre-Salt
Authors: Champion B. P. , Puntel E. A. 
Published: September 2015

Abstract
Uncertainties in reservoir connectivity and compartmentalization risk are important considerations when thinking about any new field appraisal or development options. Having a better understanding of reservoir connectivity provides benefits in determining the appropriate drainage strategy and optimizing the field development plan. By the application of a new wireless reservoir monitoring technology, based on electromagnetic (EM) communications, it is now possible to monitor the reservoir pressure and temperature response during the long term suspension of development or appraisal wells. Accurate reservoir data can now be reliably collected in the period prior to a completion string being run, or a Xmas tree being installed on the well.
Petrobras is conducting an active programme of drilling and well testing evaluation in the Pre-Salt Santos Basin area, with the objective of maximizing the collection of reservoir data that can be used to prove the reservoir models. An opportunity was identified to utilize this wireless monitoring technology in some newly drilled development wells that were to be suspended for an extended period of up to 3 years. The primary monitoring objective was to gather dynamic reservoir pressure data that could be used to identify interference effects resulting from production or injection events in the adjacent field area. Any evidence of interference will serve to prove reservoir connectivity with the adjacent well assets.
A secondary monitoring objective was to record a long term pressure build-up, beyond the end of a Drill Stem Test (DST), to check for the presence of any reservoir boundaries located far from the wellbore.
Case histories are presented for 2 installations of the wireless technology in the Brazilian deepwater pre-salt environment. The first case history presents the installation of a wireless gauge system that successfully transmitted high quality pressure and temperature data to a subsea receiver for a period of 873 days until the receiver's recovery from the seabed. The results show clear evidence of inter-well interference resulting from production in both near and far located wells. With certain producing wells being located at least 12km away from the observation well, this demonstrates that there was excellent reservoir connectivity across the field.
The second case history was targeted at monitoring for interference effects resulting from an extended well test being performed on a well located 15km away. At the time of authoring this paper the survey has been on-going for 341 days and whilst there is no evidence of connectivity, the long term pressure build-up monitoring beyond the end of the DST has provided useful data.
For both case histories the data collected has proved very useful in reducing uncertainty during the early stages of field development.