bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Shrinking Fracture Length and Decreasing Fracture Conductivity on Bottom-Hole Pressure Performance: A Semi-Analytical Model to Characterize Waterflood-Induced Fracture Around Water Injection Well
Authors: Wang Y. , Cheng S. , Zhang K. , Ayala H. L. F. , Qin J. , He Y. 
Published: April 2018

Abstract
There is growing evidence showing that water injection may induce formation fracturing around injectors in tight reservoirs. Because waterflood-induced fractures (WIFs) are not strengthed by proppants, they close gradually during the field-testing period, which results in "fracture-closure-induced" flow rate, shrinking fracture length (SFL) and decreasing fracture conductivity (DFC). In this paper, we propose a novel semi-analytical model to characterize the BHP behavior of water injectors under the influence of WIF. We consider that pressure losses take place within three sections: reservoir, WIF and wellbore. Flows between reservoir and WIF are linked through a fracture-storage coefficient and fracture-face skin factor, while flows between WIF and wellbore are coupled via wellbore-storage coefficient and choked-fracture skin factor. Finite difference and perturbation theory methods are deployed to include the SFL and DFC effects, respectively. Duhamel principle is invoked to characterize flow rate changes caused by wellbore and fracture storage effects. Results show that bi-storage effects can be identified as two unit slopes in the pressure derivative curve. In the abscense of extra pressure drop between wellbore and WIF, i.e., choked-fracture skin equals to zero, a prolonged storage period with a considerably large storage coefficient can be obtained. In addition, we find that SFL could cause the variable fracture storage effect while DFC may lead to the upward of pressure derivative curve at late times. Finally, the model is successfully applied in the Changqing Oilfield to validate its reliability.
Optimization of CO2-Foam Injection through Resistivity and Pressure Measurements
Authors: Karakas M. , Aminzadeh F. 
Published: April 2018

Abstract
This paper focuses on the use of combined resistivity and pressure measurements to determine the effectiveness of foam as a mobility control method and presents a theoretical framework to describe the expected resistivity changes during CO2-Foam displacements. With this objective, we first provide equations to estimate the resistivity for CO2-Foam systems and then utilize Population Based (PBE) and Steady-State Foam models to quantify these effects. Using analytical solutions based on the fractional flow theory, we present the corresponding resistivity and mobility distributions for both ideal and non-ideal reservoir displacement scenarios. Additionally, assuming pressure measurements only, we examine the inter-dependency between various foam parameters. Our results suggest that combination of Pressure and Resistivity measurements in time-lapse mode could be deployed as an effective monitoring tool in field applications of the (CO2) Foam processes. The proposed method is novel as it could be employed to predict under-performing CO2-Foam floods as well as improve oil recovery and CO2 storage.
A Pulsed Neutron Comparison Between an Open and Casedhole Well: An Alaskan Case Study
Authors: Burt J. , Zhou T. , Rose D. A. , Grover R. , Ahmad S. , Nemec J. , Dunston J. 
Published: April 2018

Abstract
The latest pulsed neutron spectroscopy tool for logging behind casing provides for enhanced formation evaluation due to improved self-compensated sigma and porosity measurements and a new measurement, the fast neutron cross section (FNXS), which is independent of the formation hydrogen index (HI). The FNXS is highly sensitive to gas filled porosity and can be used to differentiate between gas-filled and low-porosity zones, which was previously not possible. The FNXS measures the ability of the formation to interact with fast neutrons which is highly dependent on atomic density and not dominated by any particular isotopes, in contrast to traditional sigma and porosity measurements.
This paper examines and compares the results of gas identification and lithology identification using pulsed neutron spectroscopy in an open-hole and a cased-hole environment. Most pulsed neutron tools are run after casing; this study provides a unique example to compare the effect of casing on the spectroscopy by comparing the cased hole measurements to measurements taken in the open hole, before the casing was run.
Novel Observations of Salt Front Behaviour in Low Salinity Water Flooding
Authors: Al-Ibadi H. H. , Stephen K. D. , Mackay E. 
Published: April 2018

Abstract
The conventional method for describing transport of solutes such as salt, polymer and tracers is to use the mass conservation law. In simulation of this law for Low Salinity Water Flooding (LSWF), the effective salinity range defines how salt affects the mobility of water and appears to be crucial for controlling fluid movement. In this study, we examined the non-linear feedback between salt concentration movement and the low salinity water front as a function of physical and numerical dispersion, in combination with the effective salinity range, and we investigated how the front speeds were altered.
We examined a numerical model of the mass conservation law to simulate LSWF at the reservoir scale. The cell sizes and the time steps were chosen to control the numerical dispersion coefficient in place of physical diffusion. A range of diffusion coefficients was considered along with various representations of the effective salinity range and the function that controls the effect that salt has mobility. The latter has been shown to be variable in the literature. We compared simulations to the analytical solution of solute transport obtained for the diffusion-advection equation assuming a fixed flowing velocity.
We observed that the salinity front moved faster than was predicted by the analytical solution and this effect was increased the further the effective salinity range was set below the connate water salinity. In this case, the higher salt concentrations lay in the faster moving water (the connate water front), which also speeded up. This was very much a dispersion related effect, with the variation of velocity growing as the salt concentration spread out. By implementing many numerical tests, we obtained a modification to the advection term in the conventional mass conservation law of solute transport. This term depends on the Peclet number, the velocities of the high and low salinity fronts and the effective salinity as a proportion to the connate water salinity. In an advection-diffusion system, these factors usually affect only the advection term (the front velocity), while the diffusion term is unchanged.
From numerical tests, we can now rapidly predict the movement of the salt front by this newly derived modification of the analytical solution.
Engineered Completion and Well Spacing Optimization Using a Geologically and Geomechanically Constrained 3D Planar Frac Simulator and Fast Marching Method: Application to Eagle Ford
Authors: Paryani M. , Bachir A. , Smaoui R. , Umholtz N. , Khodabakhshnejad A. , Ouenes A. 
Published: April 2018

Abstract
Optimizing a well's hydraulic fracture design within a pad development environment is a multi-disciplinary effort and requires a 4-dimensional understanding of the reservoir. This paper presents a workflow that uses an integrated workflow that combines geology, and geomechanics to build a reservoir model which can be interrogated and updated with a geologically and geomechanically constrained grid-based 3D planar frac model and production simulation using a fast marching method. In this case, as applied to an Eagle Ford well to address concerns of completion optimization, production and depletion forecasting, well spacing and well interference.
The workflow captures the variability of stresses and rock properties along the wellbore and around it by using multiple geologic and geomechanical approaches. The estimated variability of rock mechanical properties is used as input in a 3D planar frac simulator. An alternative approach to geoengineering a completion, using the differential stress derived from geomechanical simulation that overcomes the limitations of well centric methods, is also illustrated.
The frac design results are used as inputs/constraints in a new reservoir simulator that was developed using the Fast Marching Method to estimate drainage area. This allows for a constrained, yet extremely fast estimate of the EUR and resulting pressure depletion, addressing the important concerns of well spacing optimization and prevention of frac hits and well interferences, all in a timely manner.
The integrated approach facilitates adaptive frac design which honors in-situ conditions including stress field heterogeneity, stress shadow effects and the pressure depletion from nearby producing wells. The proposed workflow enables greater investment efficiency and promotes field development optimization.
Optimization of Horizontal Wellbore Trajectory and Placement of Hydraulic Fracturing Stages in Tight Heterogeneous Gas Condensate Reservoirs Using Derivative Free Algorithms
Authors: Olusola B. , Aguilera R. 
Published: April 2018

Abstract
We present hybrid derivative free algorithm methods that maximize NPV while solving the problem of placement of hydraulic fracturing stages and horizontal wellbore trajectory in a tight heterogeneous gas condensate reservoir. These parameters are important in reservoir management and field development optimization as they determine the interaction of the wellbore with the reservoir. Thus, they have a large impact on production performance of the field and the cost of field development.
We couple a tight heterogeneous gas condensate reservoir model to an optimization algorithm that determines the parameters that maximize the economic value of the field. The optimization algorithm proposed in this paper exploits the advantage of stochastic global search (particle swarm optimization) and local pattern search (hill climber) techniques to find the optimized parameters. The optimization process starts with the particle swarm optimization (PSO) algorithm, which is executed with an initial guess based on engineering experience until the objective function (in this study NPV) fails to improve in the next couple of iterations. This is followed by the hill climber (HC) algorithm that improves the objective function.
Observations from our investigation show that an optimal field development plan (FDP) is essential to optimize the placement of hydraulic fracturing stages along a horizontal wellbore and to optimize the wellbore trajectory inside the reservoir. However, these parameters would have to be optimized simultaneously in a non-systematic manner. We integrate reservoir engineering experience and economics knowledge into the optimization algorithm by embedding practical constraints into the problem formulation.
The algorithm is executed in a reasonable amount of computation time, considering the complexity of the problem. The optimization process evaluates various possible field development plans involving different hydraulic fracturing stages and well placement trajectories. The investigation demonstrates how these parameters impact the economic value of the field, how to optimize the placement of hydraulic fracture stages along a horizontal wellbore, and how to optimize the wellbore trajectory inside the reservoir.
The methodology presented in this work should allow industry professionals working with unconventional reservoirs to improve the economic value of a field in a shorter timeframe while considering all possible field development plans, a task that would be time consuming and tedious if carried out manually.
Performance Analysis of a Novel Heavy Oil Recovery Process Using In-Situ Steam Generated by Thermochemicals
Authors: Moussa T. M. , Patil S. , Mahmoud M. A. 
Published: April 2018

Abstract
Heavy oil has attracted global attention due to its huge volume of original oil in place. However, there are numerous operation and economic challenges during the recovery of heavy oil due to its high-viscosity and high-density. Thermal recovery methods such as steam injection is viable and commonly used to recover heavy oil and bitumen primarily by thermally altering oil viscosity and improving the displacement of heavy oil. However, there are significant heat losses before the steam reaches the heavy oil, in addition to the concerns of high cost and emission of greenhouse gases. One of the promising new heavy oil recovery approaches is generating steam, in-situ, using chemical reaction to reduce the oil viscosity, improve the mobility ratio, and enhance the heavy oil displacement.
The objective of this work is to introduce a novel heavy oil recovery process using in-situ steam generated by thermal and chemical reaction and analyze its recovery performance compared with conventional steam injection method from the economic point of view, as well as based on the achieved net present value (NPV) of each technique. Sensitivity analysis of the proposed recovery processes to different operational parameters is introduced. The CMG STARS™ Simulator is used in this work to simulate reservoir models with different operational parameters. The recovery performance of the proposed technique outperformed the conventional steam flooding method and achieved higher NPV after ten years of production.
This is the first time to use NPV and consider all economic parameters to analyze the performance of the developed recovery process of in-situ steam generation by chemical reaction. This research shows that the recovery of the proposed method is economic, and applicable to the reservoirs which are not viable for conventional steam flooding methods and it is a step forward to eliminate CO2 emissions associated with thermal recovery processes.
Recovery Improvement by Chemical Additives to Steam Injection: Identifying Underlying Mechanisms Through Core and Visual Experiments
Authors: Bruns F. A. , Babadagli T. 
Published: April 2018

Abstract
Steam injection of any kind (flooding, cyclic, or gravity drainage) is a proven heavy-oil recovery method; however, it also involves excessive costs due energy and water needed for steam generation. Any effort in reducing this cost or improving oil recovery is essential for sustainable production, especially in times of low oil prices. Chemical additives to steam were suggested a few decades ago to improve two major mechanisms, namely heat transfer and interfacial phenomena, but research in that area discontinued due to the cost and thermal stability problem of the additive chemicals. With recent advancements in nano-technologies, new generation chemicals showed potential to reconsider chemical additives to improve the efficiency of steam injection. This, however, requires extensive research especially for mechanism identification. The objective of this paper is to identify the flow characteristics and the mechanisms involved in recovery enhancement by chemical additives through core and visual tests.
To mimic the gravity assisted drainage and flooding type steam displacement tests we performed previously (Bruns and Babadagli 2017) on cores saturated with 27,000 heavy-crude-oil, a visual Hele-Shaw model was designed to simulate the same process and identify the physical characteristics of the steam-condensate-oil interface and the role played by added chemicals. Majority of the chemicals/chemical blends showed either improvement in the rate or ultimate recoveries in the coreflooding tests and, based on this data, the best performing and the most thermally stable chemicals were selected for the visual tests. These chemicals include ionic liquids, internal olefin sulfonate, biodiesel (thermally stable surface active agents) and solvents (heptane), and nano-fluids (silicon oxide). The chemical solution was injected at constant rate and pressure after being vaporized in an oven along with steam and the whole process was recorded with a camera.
The contribution to recovery improvement through these phenomena in flooding and gravity controlled cases were identified. Foaming, emulsification, and IFT reduction yielding reduced drag forces between two phases at the interface were observed to be the main reason for positive contribution of chemicals. Biodiesel (Surfactant 1) exhibited a diffusion-like behavior near the injection port where no residual oil was noticed. The solvent (heptane), simulating ES-SAGD, stabilized the flow of steam in the late stage of the experiment due to the viscosity reduction. Improved oil + condensate drainage was assumed to be the contributing mechanism because of the change in surface properties during the injection of the ionic liquid. Nanoparticle, silicon oxide, and the internal olefin sulfonate (Surfactant 2) showed similar improvements in tip-splitting of the displacing fingers. It was concluded that the interfacial tension (IFT) reduction resulted in a wider occupation of the Hele-Shaw cell (better lateral sweep).
Extra Heavy Oil Production Using Dilution: Viscosity Measurement and Modeling
Authors: Alboudwarej H. , Mohan J. , Gozalpour F. , Jarvis S. S. 
Published: April 2018

Abstract
A viable method to produce a deep extra heavy oil reservoir with an in-situ viscosity in excess of 1000 cp is viscosity reduction with dilution, and where steam flooding may be an unlikely option. The objective of this study is to determine viscosity reduction of an extra heavy oil sample as a function of pressure, temperature and composition, where composition refers to addition of different amounts of diluents. Results of this study and modeling of the mixture viscosity can be used to guide future operational decision making to develop large heavy oil resources, where steam flood is not economical.
An extensive experimental test matrix was carried out in this study. A high-pressure capillary tube viscometer was used for viscosity measurements, which is the preferred measurement method for extra heavy oil systems. Potential compatibility issues such as wax and asphaltene formation due to changes in composition and/or temperature were considered during the design and execution of experimental work. In excess of 90 viscosity data points were measured for mixtures of an extra heavy oil sample and two diluents (a diesel sample and a light crude oil sample). The system pressure varied up to 4000 psia, the temperature varied in the range of 80-200 °F, and amount of diluents changed up to 40% by volume. Data QC protocols were implemented and quality of measured viscosities were assessed. Some measurements were repeated to ensure high quality of generated viscosity data.
Three to four orders of magnitude of viscosity reduction were observed with changes in pressure, temperature and composition. On average and for studied fluid systems, every 50 °F change, or 20% increase by volume in diluent concentration, reduced the mixture viscosity by almost an order of magnitude. The impact was less significant at higher temperatures and concentration of diluents. Viscosity data were used to develop specific mixture viscosity correlations for the systems of interest, representing measured viscosities with an average absolute deviation (AAD) of less than 3%. Furthermore, a large number of viscosity mixing rules were evaluated to represent measured viscosity data in this study. Some mixing rules predicted the viscosity data with 15-20 % deviation and an average standard deviation of 14%. A new mixing rule (Modified Ratcliff & Khan) was developed with an AAD of 11% and a standard deviation of 5% (at least 50% improvement in the performance).
Currently, universal viscosity mixing rules are not available, particularly for extra heavy oil and diluent mixtures. The novelty of this study is to provide a high-quality database of heavy oil and diluent viscosity data, together with the development of a new general mixing rule applicable to the type of oils and diluents investigated in this study.
Quantification of Gas Exsolution and Mass Transfer of Foamy Oil in Bulk Phase under Solution Gas Drive Conditions
Authors: Shi Yu , Yang Daoyong 
Published: April 2018

Abstract
The in-situ formation of foamy oil has been found to be a crucial mechanism accounting for the better-than-expected production performance in heavy oil reservoirs under solution gas drive. To date, the physical laws dominating gas exsolution in foamy oil have not yet been well understood, while the generation of foamy oil is essentially arose from such an extremely complicated dynamic process. In this study, a novel and pragmatic technique has been proposed and validated to quantify the gas exsolution in bulk foamy oil under solution gas drive conditions by taking into account the gas bubble size distribution and the preferential mass transfer of each gas component. Experimentally, constant-composition expansion (CCE) tests with various constant-pressure decline rates are utilized to describe the gas exsolution behaviour of alkane solvent(s)-CO2-heavy oil systems under nonequilibrium conditions, during which not only pressure and volume are simultaneously monitored and measured, but also gas samples were respectively collected at the beginning and the end of experiments to perform compositional analysis. Theoretically, a mathematical model has been formulated to quantify gas exsolution process and the preferential mass transfer between of each gas component and liquid phase in alkane solvent(s)-CO2-heavy oil systems under nonequilibrium conditions. More specifically, quasi-equilibrium boundary conditions, real gas equation and Rayleigh distribution function are combined with classical equation of motion, continuity equation, and mass transfer equation to form a novel equation matrix for quantifying gas bubble growth in foamy oil. With consideration of gas bubble size distribution and preferential diffusion of each component in a gas mixture, the total number of gas bubbles and individual diffusion coefficient of each gas component are determined by minimizing the deviation between the measured volume of alkane solvent(s)-CO2-heavy oil systems and the calculated one. More importantly, the dynamic composition of gas phase and the amounts of both entrained gas and evolved gas also can be obtained simultaneously during the gas exsolution processes. Excellent agreements between the experimentally measured parameters (i.e., volume of foamy oil, composition of evolved gas, and volume of free gas) and the calculated ones have been respectively achieved. Compared with the individual diffusion coefficient for each component in a gas mixture determined under the traditional conditions, a relatively large value has been found during mass transfer processes in a supersaturated oleic phase. Also, pseudo-bubblepoint pressure and rate of gas exsolution is found to be two mechanisms dominating the volume-growth rate of the evolved gas.