bluuebunny/crossref_metadata_2025_split huggingface dataset:
Kerogen Maturation Effects on Pore Morphology and Enhanced Shale Oil Recovery
Authors: Bui Khoa , Akkutlu I. Yucel , Zelenev Andrei , Hill William A. 
Published: April 2018

Abstract
Characterization studies of organic-rich shale oil reservoirs have revealed significant volumes of hydrocarbon fluids in kerogen. However, the recovery from kerogen pores is challenging due to amplified fluid-solid interactions. New methods can be developed for improved recovery targeting oil from kerogen pore space by modifying the forces of molecular interactions using chemical injection. A highly-developed kerogen pore-network is required for the penetration and delivery of chemical agents that are expected to function in the confined space, such surface active agents. Using advanced computational chemistry tools, the objective of this paper is to show that the maturation (the exposure to high temperature, high pressure) of kerogen during catagenesis relates to the quality of the kerogen pore network such as pore size and shape, and plays important role in the action of added chemicals in the EOR processes.
A new molecular dynamics simulation approach is developed applying dramatic changes to the organic chemicals system temperature to mimic varying degree of maturation. Simulation focuses on Type II kerogen, as it is the most common overall source of presently produced hydrocarbons. Two different chemical structures of type-II kerogen (C175H102N4O9S2, C242H219N5O12S2) are used as the building blocks to simulate the solid kerogen. The molar fractions of the elements are controlled to satisfy the overall H/C and O/C ratio of type-II kerogen in the oil window. The simulated hydrocarbon fluid consists of nine different types of molecules: dimethylnaphthalene, toluene, tetradecane, decane, octane, butane, propane, ethane and methane. The simulation box containing these molecules is subjected to a slow quenching process, which continues down to the reservoir temperature and pressure conditions. The effects of maximum temperature and the rate of quenching on the pore morphology of kerogen and the distribution of oil in the pore-network are discussed. We explain how kerogen pore morphology is controlled by the quenching rates. Next, we simulate the interaction of microemulsion droplets with the digital kerogen.
Results show that the microemulsion droplets posess elastic properties which allow them to squeeze through the kerogen pores smaller than the droplet's own diameter and to adsorb at pore wall surfaces. One major benefit associated with the use of microemulsions is the ability of the droplets to transport and deliver solvents and surfactants to different parts of the pore network. Our work shows that solvents and surfactants with particular features can be delivered in the form of a microemulsion droplet into oil saturated kerogen pore network and influence the oil mobility.
Temperature and Geometry Effects on the Fracture Surfaces Dissolution Patterns in Acid Fracturing
Authors: Aljawad Murtada Saleh , Zhu Ding , Hill Alfred Daniel 
Published: April 2018

Abstract
Modeling acid fracturing operations in carbonate formations is performed to evaluate the possible improvement in well productivity. Models are developed to mainly estimate the acid penetration length and the fracture surfaces etched-width profile. Variable combinations of these two parameters produce a significant difference in the fracture productivity. To better estimate these parameters, a reliable fracture propagation model should be coupled with the acid reaction/transport model. Simulating weak acids or dolomite formations reactivity requires the inclusion of a heat transfer model. The model provided in this study couples these factors as fractures propagate to finally obtain the fracture conductivity distribution along its length.
The fracture propagation model continuously updates the domain for the acid model. A transient acid convection and diffusion equation is solved and the fracture etched-width profile is calculated. An iterative procedure is implemented in a temperature dependent kinetic model which is stopped when both the temperature and acid solutions converge. When injection stops, acid etching and the fluids temperature are updated as the fracture closes. As the final etching profile is drawn, conductivity is calculated using a correlation that considers formation heterogeneity.
Coupling fracture propagation shows a significant difference on the acid model solutions compared to that assuming constant fracture geometry. For extremely high Peclet number that represents a very retarded acid system, a constant drop in the etched-width value until reaching zero at the fracture tip is theoretically obtainable. For lower Peclet numbers, the etching profile is shown to be sharply declining towards the fracture end. This is in contrast with the non-coupled approach from which a uniform etching profile is obtained at moderate to high Peclet numbers. It is also observed that the simulation of acid injection in non-coupled, constant fracture geometry always overestimates the acid penetration distance. The etched-width distribution and the acid penetration length are temperature sensitive, especially in dolomite formations. Temperature coupling shows that the maximum etching in dolomite formations occurs away from the fracture entrance as acid reactivity increases. It also shows that the cooling effects of the first stage pad fluid on improving the acid penetration distance is limited.
Simulating acid fracturing operations assuming constant final fracture geometry and an average single temperature is time efficient but results in inaccurate solution. This paper quantifies the effects of integrating fracture propagating and heat transfer models on the acid etching pattern from which, a better estimate of the fracture productivity is expected.
Testing and Improvement of Well Layout Optimisation Methods for Geothermal Reservoir Production
Authors: Lu Minjie , Siffert Deborah , Mathieu Jean-Baptiste , Garcia Michel , Gosselin Olivier R. 
Published: April 2018

Abstract
The development and management of geothermal reservoirs is complicated and expensive, the maximum potential geothermal energy recovery highly depending on the choice of optimal or at least relevant well locations. Within the framework of the GEOTREF research project, a multidisciplinary platform for innovation and demonstration activities for the exploration and development of high geothermal energy in fractured reservoirs, a method has been developed to optimise well layouts (location and depth) based on geothermal reservoir production performance criteria (objective functions). Objective functions such as available thermal exergy, electrical power output, leftover energy rate and simplified net present value are proposed in this paper to be used as performance criteria for identifying optimal well layouts.
The optimisation method uses the principle of superposition as a proxy-based method to simulate the production of a well layout by summing the effects of individual injection and production wells of the layout simulated separately. Using this method, the computation time required to seek optimal well layout designs is significantly reduced. The well layouts are defined based on a number of injection and production wells to be selected among many possible well locations and depths. They are all simulated using the principle of superposition and ranked according to the selected objective function. The optimal well layout is the one maximising the objective function.
Data from an actual case study is used to evaluate the method. The four objective functions are tested using reservoir simulations and sensitivity analysis based on various production parameters. The results show that the proxy-based method can simulate the performances of well layouts with sufficient accuracy, the discrepancy between proxy-based simulations and full simulations increasing with production rate. More important, the method proves to be consistent by preserving the ranks of the top one hundred well layouts under all high, medium and low production/injection rates. Preserving the ranks is the required condition that makes the proposed method reliable for seeking optimal well layouts in geothermal reservoirs. The choice of an objective function does not drastically change the areas that are recognised as good or bad for production or injection wells. Provided relevant data are available as input to the most comprehensive objective functions (i.e., electrical power output, simplified net present value), this study concludes that the proposed method is highly reliable to identify optimum well layouts in geothermal reservoirs in a relatively short computation time.
Evolution of Permeability in Sand Injectite Systems
Authors: Hu Yu , Gan Quan , Hurst Andrew , Elsworth Derek 
Published: April 2018

Abstract
Sand injectite complexes comprise kilometer-scale clastic intrusion networks that act as effective conduits for the migration, accumulation and then recovery of hydrocarbons and other fluids. An equivalent continuum model is constructed to represent a sand injectite reservoir, coupling stress and fluid flow in fractured rock using the continuum simulator TOUGHREACT coupled with FLAC3D to follow deformation and fluid flow. A permeability model, which uses staged percolation models, is proposed to improve permeability estimation of fracture networks by accommodating four different levels of fracture connectivity. This permeability model is confirmed against field and laboratory data, corresponding to the different connectivities of fracture networks. The new constitutive permeability model is incorporated into the coupled hydro-mechanical simulator framework and applied to sand injectites with the analysis of permeability evolution mechanisms and mechanical sensitivity. The results indicate that when the magnitudes of principal stresses increase in a constant ratio, normal closure is the dominant mechanism in reducing fracture aperture and thereby permeability. Conversely, the evolution of stress difference can accentuate aperture and permeability due to an increase in shear dilation for critically or near-critically oriented fractures. Also, the evolution of aperture and related permeability of fractured rock are more sensitive at lower stress states than at higher stress states due to the hyperbolic relationship between normal stress and normal closure of the fractures.
Evaluation and Optimisation of Smart Water Injection for Fractured Reservoir
Authors: Akbar M. I. , Agenet N. , Kamp A. M. , Gosselin O. R. 
Published: April 2018

Abstract
Smart water injection or low-salinity water flooding is an enhanced oil recovery technique for fractured reservoirs. The mechanism of low-salinity water flooding is performed by altering the wettability of rock towards water-wetness.
This study presents an evaluation of low-salinity water flooding based on a brown field fractured reservoir properties by using explicit simulation of spontaneous imbibition at a fine scale (single and multiple matrix block level), and assessing the validity of dual-medium simulation models, which will be further used to perform modelling at the full field scale.
Some reservoir parameters were varied within plausible range to quantify their impact on the recovery mechanism. To mitigate the biases of dual-medium models, upscaling and pseudoisation techniques were applied to match the behaviour of explicit fine-scale single-porosity model. A particular emphasis on the modelling of salt diffusion is made through one-dimension model.
It was found that, whereas pressure diffusion is rather well represented by the usual matrix-fracture exchange coefficient formalism, the underlying assumption of pseudo-steady state seems to be inappropriate for salt diffusion phenomenon.
When salt diffusion is the main driver for low salinity water imbibition, for example at the early times of a switch from high salinity to low salinity, it appears that the salt diffusion process occurs in a transient regime that cannot be properly represented by the pseudo-steady state regime assumption.
This has an impact on the modelled incremental recovery and consequently on the low salinity flooding efficiency evaluation.
Evaluating the Impact of Lateral Landing, Wellbore Trajectory and Hydraulic Fractures to Determine Unconventional Reservoir Productivity
Authors: Pankaj Piyush , Shukla Priyavrat , Yuan Ge , Zhang Xu 
Published: April 2018

Abstract
Inconsistent production performance from wells completed in similar pay zones has been observed when shale formations are exploited through horizontal wells. Ineffective completion practices, fracture design, and reservoir heterogeneity have generally been blamed for the variability in the performance. Limited importance has been attached to drilling quality and well trajectory placement in the current approaches by the operators. The objective of this study is to demonstrate an engineered lateral landing approach for improved long-term productivity in the unconventional reservoirs.
Coupling the reservoir model to the wellbore and accounting for the transient flow behavior are important for improving deliverability in horizontal wells. The study in this paper encompasses a field case study of a geocellular and geomechanical earth model in the Permian basin, which involves hydraulic fracturing modeling, reservoir simulation, fluid flowback, and transient wellbore flow modeling. Pressure losses accounted for in the reservoir, in the near-wellbore region, and in the wellbore profile are modeled and calibrated with bottomhole and surface gauge measurements. Complex hydraulic fracture geometry and numerical reservoir simulation are used to characterize the pressure losses in the reservoir. Transient wellbore fluid flow considerations are used to evaluate the pressure losses in the wellbore.
Based on the fracturing fluid type, the conductivity profile of the hydraulic fractures, connection to the wellbore, and coverage of the pay zone are important criteria in considering the landing location for wells in unconventional reservoirs. However, having the most effective hydraulic fracture design is not enough to decide the well trajectory. Mitigating liquid loading, fluid flowback, proppant settling, and cross-flow of reservoir fluid helps to diagnose the true production potential. Therefore, transient flow models were coupled to the reservoir and fracture models to design a more-effective well trajectory.
The study demonstrates the need to couple the wellbore model to the reservoir simulation and hydraulic fracturing model in shale formations to optimize well landing, trajectory profile, and long-term productivity.
The methodology provides the first integrated data workflow for well drilling and trajectory planning in unconventional reservoirs that is generated from the perspective of reservoir potential and deliverability. Although variances exist in completion effectiveness due to reservoir heterogeneity, applying the robust modeling workflow as discussed in this study would help deliver consistent results that can be used in field management and EUR estimates across various shale basins.
NanoSurfactant: A Novel Nanoparticle-Based EOR Approach
Authors: Mashat Afnan , Abdel-Fattah Amr , Gizzatov Ayrat 
Published: April 2018

Abstract
This paper describes a nanoparticle-based approach for stabilizing the low-cost petroleum sulfonate surfactants in high salinity and temperature water to enable their utility in EOR applications in typical carbonate reservoirs. The paper presents and discusses experimental results on the phase behavior of three of such NanoSurfactant formulations and their interfacial tensions (IFT) with crude oil, in order to evaluate their ability to mobilize oil during EOR operations. The three NanoSurfactant formulations were prepared through a one-step nano-emulsification process involving high salinity water, 5 wt% petroleum sulfonate solution and a low-dose of three different 4 wt% co-surfactant solutions. The resulting formulations had a 0.2 wt% of total active ingredients. One of the three formulations was persistently stable, colloidally and chemically, in high salinity water (~ 56,000 ppm) at high temperature (100 °C) for more than six months, while the other two showed signs of instability after about four months. Interfacial tensions between crude oil and NanoSurfactant solutions, measured using a spinning drop interfacial tensiometer at 90 °C, was in the 10−2 to 10−3 mN/m range and substantially lower than that with high salinity water alone or solutions of corresponding co-surfactants of similar concentrations. Phase behavior, investigated by monitoring the clarity and UV absorbance changes in a system of crude oil atop of the NanoSurfactant formulation at 100 °C without mechanical mixing, showed enhanced formation of homogeneous oil-in-water emulsions at 100 °C without the aid of any mixing. Our results demonstrate the ability of NanoSurfactants to mobilize oil under typical carbonate reservoir conditions. Their colloidal nature gives them advantages over conventional micellar surfactants by allowing them to migrate deeper in the reservoir due to size exclusion and chromatographic effects. The simple method utilized in making NanoSurfactants opens the door for better utilization of numerous low-cost, yet salinity- and temperature-intolerant chemicals in typical carbonate oil reservoir applications.
Mitigation of the Remote Gauge Problem in Temperature Transient Analysis
Authors: Dada Akindolu , Muradov Khafiz , Wang Hong , Nikjoo Ehsan , Villarreal Edsson , Davies David 
Published: April 2018

Abstract
The continuous stream of data from wells completed with multiple permanent, downhole sensors has created new monitoring possibilities. One new workflow, TTA (Temperature Transient Analysis) has proven to be particularly valuable for allocation of flow rates and phase cuts as well as for analysis of the properties of the near-wellbore formation. However, the measured temperature signal suffers considerable attenuation when the gauge is installed distant from the producing layer. This loss in signal quality has to be accounted for before carrying out TTA.
This paper investigates the effect of heat transmission in the wellbore on TTA, evaluates existing transient thermal wellbore models and develops models to reconstruct the sandface temperature from the temperature measured by a gauge located at some distance from the sandface. The possibility of estimating the thermal properties of the wellbore and surrounding formation using these models is also studied.
Two approaches are proposed for mitigating the remote gauge problem. The first approach reconstructs the sandface temperature from the degraded gauge temperature measurement data. Temperature reconstruction was found to be possible providing an accurate model of the wellbore is available. Both numerical, transient, thermal wellbore simulators and analytical thermal wellbore models may be used. Numerical inversion of the analytical transient thermal wellbore model is necessary since analytical inversion is impractical due to the result being very sensitivity to errors in measured gauge temperature.
The second approach requires producing the well under conditions that minimize the attenuation. Empirical methods may be used to quantify the heat transfer effect, when conditions are such that the transient temperature signal is "good enough" for TTA. This approach also also allows estimating the degree of uncertainty (due to wellbore heat transfer) on the TTA.
This work would extend the application of TTA to wells where analysis was previously impossible because the gauge was installed distant from the producing layer. This extension of TTA further increases the value-added by installing permanent downhole gauges.
Evaluation of Aluminium Oxide and Titanium Dioxide Nanoparticles for EOR Applications
Authors: Hogeweg Alexander Sebastian , Hincapie Rafael E. , Foedisch Hendrik , Ganzer Leonhard 
Published: April 2018

Abstract
Utilization of nanoparticles in EOR have gained high attention recently, with good but controversial results reported on improving oil recovery. Within this work two types of nanoparticles are selected and assessed, to determine its effect in oil mobilization. The experimental evaluation is performed using micromodels (EOR chips), in combination with a detailed nanofluids characterization. The workflow presented is a useful approach that can extended among different laboratories as preliminary evaluation.
The workflow comprises a set of interrelated steps: 1) Selection and preparation of the Aluminium Oxide (Al2O3) and Titanium Dioxide (TiO2) nanofluids, influenced by recent literature comparisons, 2) Detailed rheological evaluation of nanofluids and oil, 3) Investigation of the Fluid-Fluid interaction by means of the interfacial tension (IFT) and nanoparticles effects in oil viscosity, 4) Two-phase flow experiments using EOR chips (breakthrough and mobilized oil vs PV injected), 5) Image processing analysis, leading to 6) Quantitative and qualitative analysis of the experimental data.
As expected, we observed that diluting nanoparticles in fresh water increased the stability compared to brine. It was required the use of a stabilizer to optimize nanofluids characteristics. Unlike reported in the literature where Polyvinylpyrrolidone (PVP) is used, we found that adding Poly(ethylene oxide)-(PEO) leads to a more stable nanofluids. There, seemed to be a tendency for the Al2O3 nanoparticles to reduce the viscosity of the aqueous-phase, when combined with PEO. Moreover, when Al2O3 was added to the oleic-phase increased its viscosity, with a strong dependency of soaking process. The image process analysis allowed to generate algorithms to calculate concentrations and saturations among the two-phase flow experiments. These algorithms proved to be highly beneficial enabling qualitative and also quantitative analysis of mobilized oil zones, as well as plugged areas. The experimental results did not show a significantly strong increase in mobilized oil due to Titanium Dioxide nanofluids, but slightly better results were observed with the Alumnium Oxide nanofluid in a low concentration.
Much research in recent years has focused on the study of Silica nanoparticles. Since different other nanoparticles can be commercially found, this work presents additive information to the existing body of literature. Moreover, the workflow presented can be used by fellow researchers as preliminary tool for laboratory evaluations. These, to obtain potential useful insights from oil mobilization by the application of nanoparticles flooding.