bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Hydraulic Fracturing Design with Future EOR Considerations in Shale Oil Reservoirs
Authors: Nguyen Ngoc T.B. , Dang Cuong T.Q. , Chen Zhangxin , Nghiem Long X. 
Published: May 2015

Abstract
Nowadays, shale oil (SO) resources gain much attention in the oil industry world-wide. SO is classified as an unconventional resource and an optimal hydraulic fracturing (HF) design with future EOR consideration is essential for achieving a high oil production rate. However, people are still faced with many issues in HF optimization and EOR implementation associated with a significant increase in capital costs in SO development. To overcome the current challenges, maximizing the oil recovery and minimizing the future investment costs, this paper presents an HF optimization and comprehensive evaluation of EOR potential in SO reservoirs in terms of maximizing oil recovery and project revenue.
We first address the key importance for achieving a successful HF design. Then, different development strategies for improving oil recovery including waterflooding, continuous gas flooding, and cycling gas flooding are systematically evaluated. Finally, HF design and EOR gas flooding are optimized through a robust procedure.
Four parameters that strongly affect the SO production have been identified: matrix permeability, fracture half-length, fracture spacing and rock compressibility. Detailed analyses of these key factors are addressed to allow the design of optimal and practical HF strategies to maximize the oil recovery.
The analysis show that an EOR application is crucial for improving the oil recovery factor in SO. Different development strategies including natural depletion, waterflooding, and EOR gas flooding are implemented. Among them, continuous gas injection after 20 years' primary production is proven as the most promising method to improve oil recovery in both technical and economical points of views. The critical effect of a hydraulically fracturing pattern is examined in this study and it is shown that oil recovery in an aligned fracturing pattern yields a superior performance (a higher oil rate and slower pressure depletion) than the one in a staggered fracturing pattern. Moreover, the distance between an injector and a producer is investigated to obtain the highest oil production and the lowest injection cost.
To maximize the oil recovery, a series of physics-based optimizations have been performed for HF design and EOR gas operation by applying the DECE algorithm in a robust optimizer. After the optimization process, the ultimate oil recovery yeilds about 13.32% for no injection and 18.58% for gas injection. The optimal values are also documented in this paper as a guideline for future HF and EOR gas flooding in SO.
One of the important contributions of this research is to present a development strategy for SO reservoirs, in which HF optimization with future EOR considerations significantly helps to address future technical challenges, investment costs, and project economy. The proposed approach can be effectively optimized for HF design and served as a guideline for investigating the EOR potential in unconventional reservoirs.
Seismic Assisted History Matching Using Binary Image Matching
Authors: Obidegwu Dennis , Chassagne Romain , MacBeth Colin 
Published: May 2015

Abstract
This paper presents a history matching scheme that has been applied to production data and time lapse seismic data. The production data objective function is calculated using the conventional least squares method between the historical production data and simulation predictions, while the seismic objective function uses the Hamming distance between two binary images of the gas distribution (presence of gas (1) or absence of gas (0)) sequenced over the different acquisition times. The technique is applied to a UKCS (United Kingdom Continental Shelf) field that has deep-water tertiary turbidite sands and multiple stacked reservoirs defining some degree of compartmentalisation. Thirty five parameters are perturbed in this history match, they can be classified as volumetric parameters (net-to-gross, pore volume), transmissibility parameters (permeability, transmissibility), and end points of the relative permeability curves (critical saturation points). An initial ensemble of fluid flow simulation models is created where the full range of uncertain parameters are acknowledged using experimental design methods, and an evolutionary algorithm is used for optimization in the history matching process. It is found that permeability and critical gas saturation are key parameters for achieving a good history match, and that the volumetric parameters are not significant for this match in this particular reservoir. We also observe that matching only to production data marginally improves the seismic match, whilst matching to only seismic data improves the fit to production data. Combining both sets of data delivers an improvement for the production data and seismic data, as well as an overall reduction in the uncertainties. A unique feature of this technique is the use of the Hamming distance metric for seismic data history matching analysis, as this circumvents the use of the uncertain petroelastic model. This approach is easy to implement, and also helps achieve an effective global history match.
Numerical Simulation of Gas Production From Tight, Ultratight and Shale Gas Reservoirs: Flow Regimes and Geomechanical Effects
Authors: Moghaddam Rasoul Nazari , Aghabozorgi Shokoufeh , Foroozesh Jalal 
Published: May 2015

Abstract
Production from unconventional gas resources (UGRs) has received great attentions because of their large reserves as well as technical advances in developing these reservoirs. The fluid flow in ultralow permeability porous media cannot be considered in the range of conventional Darcy flow as it undergoes a transition from a Darcy regime to slip flow and free molecule flow regimes. Understanding fluid flow inside the matrix and how the matrix permeability evolves over depletion are among the major challenges to unconventional gas reservoirs characterization. Considering different flow regimes in UGRs and time dependent permeability during the production of reservoir, the applicability of the availabe numerical simulatior to predict the production from unconventional reservoirs is questionable.
In this paper, a numerical approach is proposed for simulation of gas production of UGRs including geomechanical effect, slippage effect and non-Darcy flow. In this simulation, gas production is calculated using a pseudo-pressure integral for well inflow performance and material-balance for reservoir depletion. The numerical approach has been verified by comparing with the results of fine-grid compositional simulation for a typical conventional gas reservoir. The pseudo pressure-integral has been extended to include the geomechanical effect and time dependent matrix permeability. The flow regime is distinguished by Knudsen number for each regions of the reservoir during the reservoir depletion.
According to the numerical results, the matrix permeability changes depending on the flow regime determined by Knudsen dimensionless number. Slip flow and Knudsen diffusion which are dependent on net pore pressure can play important roles in the gas production. Higher-than–expected matrix permeability becomes more highlighted when the permeability of the matrix decreases and dimensionless Knudsen number is higher than 0.1. This higher permeability enhances the gas production. On the other side, the matrix permeability decrease as the net overburden stress increases during the production life of the reservoirs. This decrease in matrix permeability clearly decreases the rate of gas production.
The presented numerical simulation evaluates the significance of different flow regimes, time dependent permeability and geomechnical effect in production from UGRs. It also offers a rapid and simple tool for prediction of gas deliverability of UGRs well.
A Diffusion Controlled Model for Prediction of Long-Term Cement Sheath Carbonation
Authors: Aiex Cristina , Campos Gilson , Chiney Abhinandan , Deshpande Abhimanyu , Patil Rahul , Paiva Maria , Ravi Kris 
Published: May 2015

Abstract
The recent increase in production from reservoirs containing in-situ CO2 and H2S; and injection of produced CO2 for geological carbon dioxide storage and enhanced oil recovery (EOR) has prompted strict risk assessment, well construction best practices, and long-term monitoring. Isolation materials used in these wells, particularly casing and cementing slurries, are to be resistant to CO2 attack. A long-term experimental approach might be too slow to meet industry needs; therefore, model-based simulation is essential to guide a design that helps ensure zonal isolation for the life of the well.
This work presents a diffusion-controlled model for simulating the conversion of cement hydration products to calcium carbonate and subsequently to water-soluble calcium bicarbonate, predicting the depth of penetration of the two reaction fronts. Temperature, total pressure, and partial pressure of CO2 are considered, corresponding to downhole conditions. After calibration with short-term experiments, the model is able to extrapolate the degradation to long term.
A simulation tool based on this model was developed and validated using available literature results and experiments performed with this purpose. Simulation results show that progress of the carbonation reaction front is faster than the subsequent conversion to calcium bicarbonate. The extent of degradation is quantified by depth of penetration of the two reactions. Strong dependency on temperature, pressure, and partial pressure of CO2 was observed. The formation permeability also plays an important role, acting as an additional mass transfer resistance.
The results demonstrate that the need for long-term experiments can be reduced or eliminated using this model-based simulation tool. The tool does not only evaluate and compare current slurry formulations, but also guides the design of new CO2 resistant materials. The extent of cement degradation attributed to CO2 injection can be predicted in downhole conditions, providing one of the most important parameters for assessing the risk of CO2 leakage in the long term, for long-term safety of wells.
A New, Accurate and Simple Model For Calculation of Horizontal Well Productivity in Gas and Gas Condensate Reservoirs
Authors: Ghahri P. , Alatefi S. , Jamiolahmady M. 
Published: May 2015

Abstract
Horizontal wells are a proven and well acknowledged technology to enhance well productivity through an increase in reservoir contact compared to that of a vertical well under the same conditions. In the last three decades, a considerable effort has been directed to study flow around horizontal wells by many investigators. These studies have mainly focused on proposing practical tools (in the form of skin factor) for long-term well productivity estimation. The skin factor proposed can be applied in an equivalent (one dimensional radial) open-hole system replicating the flow around the actual complex three dimensional (3-D) flow geometry of the Horizontal well. However, all these studies concentrate on single-phase Darcy flow conditions.
In gas condensate reservoirs, in addition to the three dimensional (3-D) nature of flow geometry, the flow behavior is further complicated by the phase change and the variation of relative permeability (kr) due to the coupling (increase in kr by an increase in velocity or decrease in IFT) and inertia (a decrease in kr by an increase in velocity) effects. Therefore, simulating such a complex 3-D flow using numerical commercial simulators requires a three dimensional fine grid compositional approach, which is very impractical, cumbersome and sometimes trigger convergence problems due to numerical instability. In fact, the introduction of a quick and reliable tool for long term productivity calculation is much needed in such systems.
This work is aimed at the development of a practical, general, and easy-to-use method for defining an effective wellbore radius of an equivalent open-hole system, replicating flow around the 3-D Horizontal well in gas condensate reservoirs.
Accordingly, a 3-D compositional finite element based in-house simulator was developed to accurately model gas and gas condensate flow around horizontal wells. A large data bank was generated, covering the impact of a wide range of pertinent geometric and flow parameters on the well performance. Then a general approach is proposed for estimation of an effective wellbore radius of an equivalent open-hole radial 1-D system replicating flow around the 3-D Horizontal well system. The effective wellbore radius varies with fluid properties, velocity, IFT, reservoir and wellbore conditions. The results of the proposed formulation, which benefits from suitable dimensionless numbers, has been tested against the simulator results not used in its development confirming the integrity of the approach. Also, the proposed formulation is applicable for both single-phase non-Darcy and two-phase gas condensate flow systems.
With this approach, no numerical simulation is needed and instead a simple excel spread-sheet can predict the horizontal well performance, significantly facilitating engineering and management decisions relating to the application of horizontal well technologies.
Full System Analysis to Predict the Reliability of a Wastewater Disposal System; a Hydraulic Simulation-Based Approach
Authors: Al-Hajri Nasser M. , Al-Ajmi Mohammed D. , Al-Subaie Fehead M. 
Published: May 2015

Abstract
The increase in water production from mature fields calls for continuous monitoring of wastewater disposal (WWD) system capacities. The three main components of any WWD system are discharge pumps, pipeline's network and disposal wells. Situations may arise when the full system capacity is constrained by the flow performance of one or a combination of these components. Subsequently, produced water volumes are reduced by closing high water cut oil producers. The grave and critical importance of such systems necessitates proactive diagnosing and forecasting of WWD performances.
Plant-A injects 45 thousand barrels per day (MBD) of wastewater into five disposal wells. Historical system performance showed an increase in the pump discharge pressure that has nearly reached its maximum operating limit. A variation in injection performance among all the five disposal wells was observed. This variation is attributed to the different completion designs and reservoir inflow performances of the five subject wells. A 14 km flow line of varying sizes connects the disposal wells to two parallel discharge pumps. These pumps are designed to inject the abovementioned rate at a discharge pressure of 800 psi at current conditions.
A full system analysis of Plant-A disposal network, utilizing hydraulic simulation techniques, was performed to model the current injection performance. The goal of this comprehensive study of the disposal system was to explore all possible root causes of the discharge pressure increase. In addition, the hydraulic simulator forecasted several feasible and recommended scenarios to eliminate this high discharge pressure.
The five disposal well's inflow and outflow performance relationships were generated and calibrated using actual injection data. Network flow analysis was performed to account for both frictional and gravitational pressure losses in pipelines and flow restrictions using sophisticated software. This high accuracy model improved the decision making process and an optimized solution was put into effect based on the simulation results.
Reservoir Flow Simulation Coupled Rock Mechanics for Modeling Shale Liquid Rich Gas Play
Authors: Lin M. , Wang S. , Chen S. , Chen Z. 
Published: May 2015

Abstract
Multistage hydraulic fracturing technique now applied with horizontal wells and over large areas has enabled commercial production of oil and gas from low-permeability rock formations, changing the energy landscape in North America. In these reservoirs, tons of fracturing fluid and proppants are pumped into the reservoir matrix to create hydraulic fractures and it is important to understand the propagation mechanism of hydraulic fractures and further optimize their properties. In addition, natural fractures are often present in the shale and tight formations, which might be activated during the fracturing process and contribute to the after-stimulation well production rates.
In this paper, reservoir simulation is coupled with rock mechanics to predict the well after-stimulation production performance. Firstly, a dual-permeability geological model is built based on field data collected from a well pad in Montney formation, Canada. Fracturing fluid flow in the formation coupled rock mechanics is employed to simulate dynamic hydraulic fracturing process. More specifically, as the continuous injection of fracturing flurry, the effective stress will decrease accordingly. When the effective stress reaches the rock failure criteria, hydraulic fractures will be generated, allowing the fracturing liquid to flow along the fractures. Based on the fracturing operational schedule, dynamic hydraulic fracturing simulation is conducted and results show that hydraulic fractures tend to propagate upward first until it connects the entire formation in the vertical direction. Early production history of the stimulated well is then matched to valid the simulated fracture geometries. Finally, the effects of natural fractures and well bottom-hole pressure on well production are studied. Results show that if natural fracture can be propped or partially propped by the proppants, the production will be increased significantly for shale liquid rich gas plays. This paper provides a significant insights on the fracture propagation and can be a reference for fracturing treatments in unconventional shale reservoirs.
Minifrac Analysis Using Well Test Technique as Applied to the Vaca Muerta Shale Play
Authors: Rohmer B. , Raverta M. , Boutaud de la Combe J-L. , Jaffrezic V. 
Published: May 2015

Abstract
In shale gas, permeability is so low such that radial flow is rarely reached and only fracture flow is observed. Minifrac test interpretation is therefore a non unique process as the flow observed are governed by several unknown parameters, fracture geometry, formation permeability and pressure.
The industry tends to use unique fracture geometry and single pressure estimation such as linear flow extrapolation in order to reduce the interpretation to a unique case. This paper presents a new approach which enables to characterize the range of permeability and pressure. Pressure Transient Analysis tools are used in order to interpret minifrac tests before and after closure period. The common lack of radial flow results in an infinite range of possible permeability and initial pressure scenarios. These can be constrained by considering different simplified 2D fracture geometry. These constrained scenarios, resulting in a limited range of possible values for these two parameters, can then be tested with Rate Transient Analysis which otherwise has also non-unique solution.
First and foremost, this work shows that uncertainty on initial pressure can be low, as even extreme cases can yield pressure difference in the order of only a few tens of psi. However, small differences in pressure can lead to permeability estimation with a range up to several orders of magnitude.
The consequence of considering only a single pressure value is to neglect the potential uncertainty in permeability estimation. Describing the uncertainty on these parameters should be a compulsory output of a minifrac interpretation in shale formations.
This paper also demonstrates that when radial flow is not observed, a straight line analysis gives only a maximum value of permeability thickness and linear flow extrapolation is only one value amongst the possible range. This pressure can be associated to unrealistic fracture geometry.
The methodology is applied to a shale gas exploration well in the Vaca Muerta formation. The production data and the Rate Transient Analysis over the first year of production proved the validity and benefits of this approach.
In a nutshell, using this methodology enables to determine the range of possible pressure and permeability at the very early life of the well simply based on a minifrac before and after closure interpretation. This method in comparison to a commonly performed single case interpretation allows estimating the impact of permeability uncertainty on production forecast after only a few months of production.
The Convective-Diffusive Mechanism in CO2 Sequestration in Saline Aquifers: Experimental and Numerical Simulation Study
Authors: Foroozesh Jalal , Moghaddam Rasoul Nazari 
Published: May 2015

Abstract
Carbone Dioxide can be injected into the saline aquifers and securely stored underground if it is dissolved in water. When CO2 contacts water, it starts to diffuse through the interface and the water layer near to the interface becomes CO2 saturated and denser. The heavier saturated layer induces a gravitational instability (disturbance) which can result in fluid convection. This natural convection significantly increases the rate of CO2 dissolution. Despite a decade of research on this area, this complex mechanism is not fully understood. In addition, mathematical modelling of this process by solving the equations of momentum balance coupled with convection-diffusion is challenging.
In order to better understand and study the important parameters affecting the instability of the diffusive layer, a series of visual experiments were performed. A vertical, two-dimensional Hele-Shaw setup composed of a flat glass plate and a flat aluminum plate has been designed to investigate the instability of saturated layer. It has been partially filled with brine with salinity of 20 wt% containing pH sensitive dye of litmus powder. CO2 was introduced into the top of Hele-Shaw cell with the initial pressure of 100 psi. Experimental results clearly shows the onset of instability and the natural convection phenomenon when the start point of CO2 fingering and its propagation through the water phase were recorded.
Experimental data were also used to simulate the process using the conventional and a new proposed model. In this study, a new model has been proposed to be used instead of the conventional one. Conventionally the governing equations including momentum balance equation coupled with convection-diffusion equation are solved to simulate the disturbances. In addition, in this study, a new approach is proposed. In this model, a pseudo diffusion coefficient is introduced into the unsteady-state diffusion equation based on the second Fick's law. A so-called pseudo diffusion coefficient was defined as a function of time to capture the variable dissolution rate occurring during CO2 dissolution in brine. The proposed model was consistent with conventional model in prediction of CO2 dissolution rate.
The results of this study can help to better understand the dissolution mechanisms of CO2 in brine. Moreover the developed model here can be used as a rapid and simple method to predict the CO2 dissolution behaviour for other systems with different scales and properties. Additionally the idea of pseudo diffusion coefficient can be used in other systems when the convection can be represented by the diffusion.