bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Hydrocarbon Recovery using Mixtures of Energizing Chemicals in Unconventional Reservoirs
Authors: Mohanty Kishore K. , Tong Songyang , Miller Chammi , Honarpour Matt M. , Turek Edward , Peck Doug D. 
Published: October 2017

Abstract
The goal of this work is to design and evaluate an effective blend of energizing chemicals that can be injected into shale (black oil or critical fluid) reservoirs to enhance hydrocarbon recovery. The blend can be implemented as the pre-pad fluid ahead of hydraulic fracturing fluid or as a treatment fluid later in the life of a well. As a means to increase recovery, an energized chemical blend (CB) consisting of an organic solvent, a surfactant, an oxidizing agent (and acid) was designed, developed and tested on crushed rock, core plugs and fractured cores in the laboratory to evaluate the interactions of the chemicals with the shale samples. Micro-CT scanning and scanning electron microscopy were used to visualize morphological changes in the shale. A pilot was designed in an existing pad with stable production so that the benefits could be quantified on production rate and recovery.
The results of laboratory experiments demonstrate that the chemical blend extracts up to 30% of mobile oil in crushed rocks and improves permeability by 25-100% in thin core plugs. Some of the factors that support the success of the chemical blend application are: I- Pressurization of the formation and reopening of the closed fractures, thus improving the well productivity, II- Extraction and mobilization of low mobility oil, remnants of the original kerogen, removal of deposited salt and trapped water in matrix and fracture network that impedes fluid flow, III- Creation of pathways to high-pressure liquids-rich small organic pores, where undersaturated hydrocarbon liquids are trapped, adsorbed and dissolved in the kerogen, IV- Creation of flow pathways for intrusion of aqueous based fluids in oil-wet organic rich rocks with wettability alteration to accelerate the injection, counter-current imbibition and osmosis processes, V- Enhancement of porosity and permeability of fracture surfaces by introduction of a delayed reaction mechanism to deliver acids deeper into the microfracture network without compromising rock mechanical properties. The presence of sulfate ions in the oxidizing agent did not contribute to any noticeable scale deposit while delaying the reactivity of acid with inorganic components of shale surfaces. Laboratory and field pilot results are employed to calibrate a discrete fracture network (DFN) model of the pilot well and the surrounding Eagle Ford formation. The model is used to design and optimize CB injection in future applications.
Simulation of Hydraulic Fracturing-Induced Permeability Stimulation Using Coupled Flow and Continuum Damage Mechanics
Authors: Samnejad M. , Aminzadeh F. , Jha B. 
Published: October 2017

Abstract
In hydraulic fracturing operations, permeability is enhanced when fractures are created and/or stimulated by injecting a highly pressurized fluid. In addition, mechanical response of the rock changes because of permanent modifications in the structure and properties of the rock after failure. In order for engineers to accurately predict results of hydraulic stimulation projects, mathematically rigorous and numerically efficient models of fluid flow and geomechanical deformation in fractured porous media must be used in computer simulations. Some of the earlier approaches address the problem of fluid flow through fractured media with mathematical models that are either too simplistic or too expensive computationally and are not compatible with the available petroleum reservoir simulation platforms. In this work, a reservoir simulation framework is developed using a sequentially coupled numerical scheme of flow, deformation and poromechanical damage to study variations occurring in the fractured rock properties and state variables as a result of hydraulic stimulation. We numerically simulate injection-induced permeability enhancement and plastic deformation as well as post-stimulation softening behavior of the rock by considering the stimulated rock as a mechanically damaged configuration, the properties of which are modeled using an effective continuum model. We study how the flow and mechanical properties of fractured rock, namely permeability and stiffness, change by virtue of hydraulic fracturing, and we investigate the dynamics of pressure distribution and stress state with time. The sequential nature of the proposed coupling framework lends itself to easy integration with reservoir simulation and prediction tools.
Case History - Continued Diagnostic Technology Integration with Completions in Horizontal Wolfcamp Shale Wells in the Delaware Basin
Authors: Parker Justin E. , Tran Van P. , Bazan Lucas W. , Thomas Jonathan , Renze Arden 
Published: October 2017

Abstract
Parker et. al., (2015), SPE 175535, presented an engineered completion methodology utilizing diagnostic technology integration relating to horizontal shale wells in the Delaware basin. That paper focused on technologies pertaining to hydraulic fracture design for the Wolfcamp A reservoir using a discrete fracture network (DFN) model for predicting fracture geometry, formation evaluation, oil tracers, microseismic monitoring and production history matching. The final results of the paper showed that the application of an integrated technology approach provided the operator with a systematic method for designing, analyzing, and optimizing multi-stage/multi-cluster transverse hydraulic fractures in horizontal wellbores. Since publishing the paper, the completion and fracture stimulation design methodology has been further extended with improved well performance.
This new work presents longer term well results from the original paper and additional wells that have since been completed with design improvements based on this process. Further technologies have since been added to the completion processes which have enhanced well performance, including the application of rate transient analysis (RTA) analysis, applied post job engineering analytics (APJA), additional pressure history matching (PHM) and post-fracture pressure matches to help refine the DFN model. The purpose of this work will be to further outline the benefits of utilizing multiple diagnostic technology integration to design, analyze and optimize completion and fracture stimulation design in the Wolfcamp shale. Detailed discussion related to created and propped fracture half-lengths, estimates of minimum conductivity, perforation design and cluster efficiency are presented. The value of diagnostic technology, EUR considerations and well economics will also be addressed.
Readers of this paper will gain insight on how sound engineering, fracture modeling and data integration can increase recovery and optimize completions in the Wolfcamp and Bone Spring formations. Those working in the Delaware and Midland basins can readily apply specific learnings from this work to new completions. Additionally, the methods and engineering principles presented in this paper will provide a basis-of-design to enhance productivity and well economics for horizontal wells in unconventional resources.
3-D Visual Experiments on Fluid Flow Behavior of Water Flooding and Gas Flooding in Fractured-Vuggy Carbonate Reservoir
Authors: Qu Ming , Hou Jirui , Zhao Fenglan , Song Zhaojie , Ma Shixi , Wang Qian , Li Meng , Yang Meng 
Published: October 2017

Abstract
Tahe oilfield is one of the most important fractured-vuggy carbonate oilfields in China. The characteristics of this kind of reservoir are greatly complex due to its multiple flow units: matrix, fractures and vugs. The main problems during development include the complicated oil-water relationship and the lack of fluid flow mechanism etc. However, one- and two-dimensional physical models due to its limitations cannot overall reflect fluid flow status.
Based on Tahe oil field geological conditions, a 3-D visual fractured-vuggy physical model was designed and fabricated according to similarity criterion. Bottom water drive, water flooding and gas flooding were conducted in this model. Multiphase flow behavior was recorded by high resolution camera system and the pressure response was monitored at different oil displacement stages. Finally, the effect of different energy complement methods was discussed.
Experimental results show that the 3-D visual physical model can be used to systematically and comprehensively investigate the fluid flow status and the oil displacement process. The pressure response presented different characteristics at different flooding stages. The fractured-vuggy structure and the ratio of displacement force and gravity determine the water/gas flooding behavior. The fluid flow mechanisms were discussed combining the pressure response and dynamic displacement phenomenon. Regarding displacement effect, water breakthrough and even serious water channeling occur more easily in fracture well than vuggy well. And water cut increases dramatically in fracture well.
Compared to one- and two-dimensional physical models in previous studies, the 3-D visual physical model proposed here is more representative of the real reservoir conditions. This study could provide a constructive guide for the fractured-vuggy carbonate reservoir to improve production performance.
Inflow Control Device Injection and Production Dynamic Integrity Testing – Best Practices
Authors: Jackson M. S. , Mayer C. S. , Shuchart C. E. , Dornic S. D. , Tayloe G. L 
Published: October 2017

Abstract
In recent years, the application envelope for inflow control devices (ICDs) has significantly shifted toward harsher environments, for example, to high temperature changes for SAGD, high production pressure differentials in wells with high reservoir permeability contrast, and extreme pressure differentials during short-duration acid stimulation. To confirm whether ICDs are able to withstand these extreme conditions, representative and reproducible equipment testing must be performed. The objective of this paper is to describe testing methods and results for a new type of design validation test related to mechanical integrity of production ICDs when operated at high pressure differentials with both injection and production flow as might be observed during either short-duration acid treatments or initial clean-up operations.
A method is presented for validating multiple ICD designs via full-scale testing at high pressure differentials. The first part of this test consists of a flow-to-failure test where the flow rate is incrementally increased until the ICD design flow characteristics are altered (permanently or temporarily). ICD performance may change due to shifting, deformation, and/or loss of sealing surface contact of critical internal components under the loading condition, causing an increase in flow area. A notable change in the ICD flow characteristics is considered to represent the critical upper differential pressure limit. A separate endurance test is also performed with a new ICD at a safety factor adjusted burst rating to determine the integrity of the ICD design over an extended flow period.
This new test method has been applied to several ICD designs over the past few years. Testing outcomes range from unexpected changes in performance characteristics of some ICD designs (cracking of internals, ballooning of the ICD housing, and failure of critical seals) to no apparent failure up to the pressure limit of the flow loop. Lessons learned from testing via this protocol have encouraged service companies to improve their ICD designs, thereby providing more reliable and robust products to the industry.
When these testing programs were initiated, there wasn't an industry-wide accepted best practice for testing ICDs. To build a base of accepted test procedures and methods for ICDs, this paper describes the fundamentals of a new method involving flow-to-failure and endurance validation testing. The methods represent a specific procedure that can be used by oil-field operators as guidelines for specifying validation techniques for untested ICD designs. These methods have now been incorporated into the AWES RP 3362-78 Annex F (2017).
Proximity Sensing: A Novel Approach to Reservoir Saturation Monitoring Using High Frequency Electromagnetic Pulses
Authors: Felix S. Jesus M. , Ellis Erika S. , Schmidt Howard K. 
Published: October 2017

Abstract
Proximity Sensing is a recently introduced approach to reservoir characterization, which uses high frequency, pulsed electromagnetic (EM) signals that are propagated through naturally occurring transmission lines adjacent to oil reservoirs, such as continuous anhydrite layers that serve as the seal for major carbonate reservoirs in and around the GCC. While propagating through the anhydrite channel the pulse is modulated by the saturation properties of the adjacent reservoirs. Previous 2-D simulations demonstrated the feasibility of using the anhydrite as a low loss transmission line and showed the potential to detect changes in reservoir saturation adjacent to the propagation channel. This work presents further verification of the Proximity Sensing method with 3-D simulations including antenna modelling and polarization effects, dependence of EM modulation with reservoir saturation changes and injection water flood front mapping capabilities. A series of models were created to study the effect of the conductivity and permittivity of the reservoir and the polarization of the EM pulse. The effect of varying each of the EM properties of the reservoir on the speed of propagation of the pulse and the polarization of the antenna is presented. The data shows that in general, large contrasts in conductivity and/or permittivity between the anhydrite channel and the adjacent reservoirs will confine the signal within the anhydrite and will result in shorter travel times than in the absence of strong contrasts. For the purpose of detecting oil and saline water this means that if the reservoir adjacent to the anhydrite is saturated with water the EM pulse will travel faster and the signal will have greater amplitude. In contrast, if the adjacent reservoir is oil saturated and EM signal will slow down and will display lower amplitude. This work aims to identify the most important variables needed to take this approach to small scale field testing. The success of Proximity Sensing would provide an accurate and inexpensive method to characterize reservoir saturation and flood front progression either as part of a logging operation or as a standalone sensing platform.
A Novel Bayesian Optimization Framework for Computationally Expensive Optimization Problem in Tight Oil Reservoirs
Authors: Wang Shuhua , Chen Shengnan 
Published: October 2017

Abstract
Multi-well pad has been considered as the most efficient horizontal-well drilling technique in unconventional reservoir development since it not only greatly maximizes the oil production, but also significantly reduces environmental impact and operation costs by drilling group of wells on a single pad. To optimize both hydraulic fracture parameters of each well and well placement simultaneously is still largely unexplored and remains to be a challenging task. Conventional optimization techniques, such as genetic algorithm, particle swarm optimization, and differential evolution algorithm are inadequate to optimize production performance in the multi-well pad, because it may take hours to days to run a single reservoir simulation, leading to an unaffordable computational cost for the optimization processes.
To speed up the search process of global optimization in reservoir simulations, a novel optimization framework for computationally expensive simulations is developed based on Bayesian optimization algorithm. The newly developed optimization algorithm constructs a probabilistic model for the objective function and then exploits this model to make decisions about where in search space to next evaluate the function. In this study, Gaussian Process (GP) is utilized to construct the prior distribution over the objective function. Then, the posterior over functions is obtained based on the prior distribution and evaluations of objective functions. Finally, acquisition function is developed through maximizing the expected improvement over the current best from the posterior, allowing us to determine the next point to evaluate in search space.
It is shown that GP Bayesian optimization framework can successfully optimize the hydraulic fracture parameters and horizontal well placement simultaneously in tight oil reservoirs. 19 parameters involve well spacing, well length, fracture spacing, fracture half-length, and fracture conductivity in a four-well pad were optimized and a high net present value (NPV) was achieved. The oil recovery and NPV of the optimum scenario derived through the Bayesian optimization technique are increased by 36.0% and 55.7% respectively in comparison with a field reference case. The proposed Bayesian optimization framework is found to be a promising and efficient optimization strategy, which takes full advantage of the information available from previous evaluations of objective function, in handling the computationally expensive optimization problems.
Phase Behavior in Shale Organic and Inorganic Nanopores From Molecular Simulation
Authors: Jin Bikai , Nasrabadi Hadi 
Published: October 2017

Abstract
Production from shale reservoir is getting more attention from the oil industry. However, the shale is not understood as well as conventional reservoirs. One complexity is the unclear fluid phase behavior in shale nanopores. In previous work, the shale rock is usually built as a simple model without consideration of the material effect on phase behavior. To have a better understanding of phase diagrams in different shale environment, three materials (two inorganic minerals and one kerogen) are used in this work to generate two types of nanopores (slit and cylinder), which are adopted in the phase behavior simulations of pure fluids (methane and propane) and one ternary fluid (C1/C3/nC5). From the pure fluid tests in pores of three diameters (4, 7, 10 nm), confined liquid densities are decreased while vapor densities are increased in slit and cylinder pores. Critical points are shifted to lower densities and higher temperatures. Group tests are conducted for the ternary fluid in slit and cylinder pores at one temperature (160 °F). Under confinement, there is a big shift in the nC5 composition of the vapor phase in the ternary diagrams while only small changes have been observed in the liquid composition. The density difference between two phases is reduced. Additional tests are performed at one typical shale temperature (290 °F) for this ternary fluid in both pore types. Phase separation is computed in slit pore tests while only one phase is formed in tests of cylinder pores. Since the cylinder pore has more adsorption surface area, compared with the slit pore, a stronger adsorption effect is introduced in all tests of cylinder pores. Based on the comparison of all results (pure fluids and ternary case) from three materials, the calcite pores provide stronger confinement effect on fluids and the other two materials have the similar confinement effect on phase diagrams.
Stress-Induced Damage Evolution in Unconventional Shale Monitored by Acoustic Emission
Authors: Jin Guodong , Ali Syed Shujath , Muqtadir Arqam , Hussaini Syed Rizwanullah , Nair Asok , Alshanqaiti Elham , Khodja Mohammed R. , Ali Abdul Wahab 
Published: October 2017

Abstract
This paper experimentally investigates the damage evolution (or the deformation process) induced by externally applied stress on unconventional shale samples. The focus is to understand the physics behind the complex failure process occurring at the micro-scale, and thus provide useful information on the macro-fracture mechanisms of unconventional shales. We perform the compression tests along with the acoustic emission (AE) measurement on cylindrical rock samples selected from Berea sandstone (BS), Eagle Ford (EF) and Marcellus formation. Tests are conducted under the same stress condition: uniaxial unconfined compression test and triaxial compression test with a confining pressure of 10 MPa. AEs are continuously collected to characterize the progressive damage process. The axial stress, axial and radial displacement are also recorded during experiments. Shale samples are drilled perpendicular or parallel to the beddings. The X-ray diffraction (XRD) analysis is used to measure the mineralogy and clay content. Prior to geomechanical testing, the high-resolution micro-CT imaging system is used for quality assessment of rock samples and characterization of microstructure and fracture presence.
All samples studied exhibit distinct characteristics of AE counts. In Berea sandstone, AE counts initially increase slowly with the axial strain, and then surge dramatically after reaching the yield stress point. This is consistent with the observed stress-strain behavior: a linear elastic part followed by the inelastic deformation till the rock fails. Compared to Berea sandstone, shale samples show a different characteristics of AE counts. AEs resulting from EF vertical sample monotonically increase until the sample fails, while three stages of AE activity are observed in the horizontal sample: initial increase followed by a stage of quiet period (no AE events), and increase again. Marcellus samples behave just the opposite: three stages of AE events are observed in the vertical sample, while monotonically increase in the horizontal sample. AEs are also observed to be affected by the test condition: different from the triaxial compression test, Marcellus vertical and horizontal samples have a similar trend in AE counts during the uniaxial compression test. Both initially increase in AE activity with the axial stress, and after a certain stress, a surge in AE activity is observed. The observed discrepancy of AEs can be due to the complexity of shale mineralogical compositions, pore geometry and thin layer structure. More detailed laboratory experiments are necessary to understand the physics behind the complex failure process and AEs occurring at the micro-scale in unconventional shales.
A Novel Mechanism of Alkaline Flooding to Improve Sweep Efficiency for Viscous Oils
Authors: Xiao Rong , Teletzke Gary F. , Lin Michael W. , Glotzbach Rodney C. , Aitkulov Almas , Yeganeh Mohsen , Jaishankar Aditya , Hegner Jessica 
Published: October 2017

Abstract
A mechanism of alkaline flooding to improve recovery for viscous oils was found to be related to the transition of emulsions from low viscosity and low water-oil-ratios (WORs) to high viscosity and high WORs. Distinct behaviors of emulsions formed by alkaline brines and acidic, viscous oils were experimentally observed by mixing alkaline brines and oils at different WOR. Depending on the oil type and the brine formulation, different transition behaviors of the emulsions were observed. In some cases, low viscosity oil-in-water (O/W) emulsions were observed at low WOR while high viscosity water-in-oil (W/O) emulsions were observed at high WOR. This transition of emulsion type and properties was associated with significant uplift in recovery by alkaline flooding over water flooding as observed in sandpack floods. Meanwhile, when the emulsions did not exhibit transitional behaviors and remained the same type with varying WOR, the incremental recovery by alkaline flooding was very small, regardless of whether the viscosities of the emulsions were high or low. A novel mechanism associated with flow re-direction and sweep efficiency improvement was proposed and validated using micromodel experiments. Results of this work lead to new opportunities and screening criteria to apply alkaline flooding for viscous, acidic oils.