bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reactive vs Proactive Intelligent Well Injection Evaluation for EOR in a Stratified GOM Deepwater Wilcox Reservoir using Integrated Simulation-Surface Network Modeling
Authors: Da Sie Will , Oghena Andrew , Seth Gaurav , Ouyang Liang-Biao , Ghoraishy Mojtaba 
Published: September 2019

Abstract
Improved field management for monitoring, estimating zone productivity/injectivity, and controlling wells with intelligent completions can broaden application of advanced well designs. We have developed a coupled Simulation-Surface Network modeling workflow to evaluate the potential benefit of intelligent injection profile control with a focus on reactive vs proactive control for Gulf of Mexico (GOM) Deepwater Enhanced Oil Recovery (EOR) schemes. The developed injection control solution can be consistently applied to gas, water injection, and gas followed by water injection, to evaluate relative impacts of intelligent injectors on each option. We did this by defining rules for both proactive and reactive injection ICV controls for a GOM Deepwater Wilcox multilayered reservoir. Proactive controls, based on reservoir zone characteristics, pore volume injected, and recoverable pore volume, are dependent on a static reservoir model realization. Proactive control results demonstrate a diminishing return as we begin to observe fluid breakthroughs that results in part from the inevitable uncertainty of the original static assessment so there should be a benefit in reassessing optimal pore volume injection based on reservoir model updates. Reactive control strategies based on measured production response is a challenge in terms of linking injection control events to production responses that are time-lagged and incomplete for understanding gas and water breakthrough. The integrated model captures the effects of topside facilities, risers, flowlines, pressure/temperature at manifolds and topside, seafloor booster pump performance, wellheads, and wellbore to reservoir interactions and ICV controls to provide a realistic evaluation of achievable development alternatives outcomes.
Oxygenated Solvent as a Novel Additive for Improved Oil Recovery in Tight Oil Reservoirs
Authors: Wang Mingyuan , Baek Kwang Hoon , Abeykoon Gayan A. , Argüelles-Vivas Francisco J. , Okuno Ryosuke 
Published: September 2019

Abstract
Tight oil reservoirs typically show rapid reduction in production rate within a few years. Various methods of improved oil recovery from tight reservoirs have been studied, such as cyclic injection of gas and chemical solutions. Chemical solution injection is expected to improve oil recovery through wettability alteration and water/oil interfacial tension (IFT) reduction because most tight oil reservoirs are reportedly intermediate- to oil-wet.
This paper presents a comparative study of two wettability modifiers with different characters for enhancing water imbibition from a fracture into the surrounding matrix. One is 3-pentanone, a symmetric short ketone, and the other is 2-ethylhexanol-4PO-15EO, a non-ionic surfactant with an ultra-short hydrophobe. They were used as low-concentration additives (approximately 1 wt%) to reservoir brine (RB) in this research.
Contact-angle experiments with oil-aged calcite surfaces showed that the two chemicals are comparable as wettability modifiers. For example, the surfactant solution was able to change the contact angle of oil droplets on oil-aged calcite surfaces from 134° to 47° within a day.
Coreflooding experiments using fractured limestone cores showed that the 3-pentanone solution resulted in more rapid oil recovery by water imbibition than the surfactant solution. The incremental oil recovery factor was 30.9% for 1.6 pore-volumes injected (PVI) of the 3-pentanone solution and 8.4% for 1.2 PVI of the chase RB. For the surfactant case, it was 23.6% for 1.6 PVI of the surfactant solution and 23.7% for 7.0 PVI of the chase RB.
The difference in oil recovery response between the two chemical solutions was attributed to their different characters as wettability modifiers; that is, the surfactant solution lowers the water/oil IFT from 11 mN/m to 0.21 mN/m, but the 3-pentanone solution does not. The 3-pentanone solution can keep the original water/oil IFT, and increase the capillary force for water imbibition by wettability alteration. The importance of lowering the water/oil IFT was observed during the extended chase RB injection after the surfactant slug. The oil recovery in the surfactant case was increasing even after 7.0 PVI of the chase RB.
Nanofluidic Analysis of Flowback Enhancers for the Permian Basin: Unconventional Method for Unconventional Rock
Authors: Quintero Harvey , Abedini Ali , Mattucci Mike , O’Neil Bill , Wust Raphael , Hawkes Robert , De Hass Thomas , Toor Am 
Published: September 2019

Abstract
For optimizing and enhancing hydrocarbon recovery from unconventional plays, the technological race is currently focused on development and production of state-of-the-art surfactants that reduce interfacial tension to mitigate obstructive capillary forces and thus increase the relative permeability to hydrocarbon (kro). This study provides insight into the pore-scale evaluation of the latest flowback enhancer technologies currently applied in the Permian Basin, Texas, USA. A multidisciplinary approach, including concepts of nanotechnology, was used to assess fluid-fluid and rock-fluid interactions occurring at the nanopore scale and their implications on enhancing oil recovery.
A heterogeneous dual-porosity dual-permeability microfluidic chip was designed and developed with pore geometries representing shale formations. This micro-chip simulated Wolfcamp shale with two distinct regions: (i) a high-permeability fracture zone (20 µm pore size) interconnected to (ii) a low-permeability nano-network zone (100 nm size). The fluorescent microscopy technique was applied to visualize and quantify the performance of different flowback enhancers during injection and flowback processes.
This study highlights results from the nanofluidic analysis performed on Wolfcamp Formation rock specimens using a microreservoir-on-a-chip, which showed the benefits of the multi-functionalized surfactant (MFS) in terms of enhancing oil/condensate production. Test results obtained at a simulated reservoir temperature of 113°F (45°C) and a testing pressure of 2,176 psi (15 MPa) showed a significant improvement in relative permeability to hydrocarbon (kro) in the nanomodel when MFS was added to the stimulation fluids at loadings as low as 0.05% v/v. The results were compared against other premium flowback enhancers.
Measurements using a high-resolution spinning drop tensiometer showed a 40-fold reduction in interfacial tension when the stimulation fluid containing MFS was tested against Wolfcamp crude at 113°F (45°C). Also, MFS outperformed other premium surfactants in Amott spontaneous imbibition analysis when tested with Wolfcamp core samples.
This work used a nanofluidic model that appropriately reflected the inherent nanoconfinement of shale/tight formation to resolve the flowback process in hydraulic fracturing, and it is the first of its kind to visualize the mechanism behind this process at nanoscale. This platform also demonstrated a cost-effective alternative to coreflood testing for evaluating the effect of chemical additives on the flowback process. Conventional lab and field data were correlated with the nanofluidic analysis.
An Integrated Approach in Characterization of Triple Porosity Nisku Reefs Alberta: A Quest from Core and Borehole Images to 3D Earth Model
Authors: Zaluski Wade , Andjelkovic Dragan , Xu Cindy , Rivero Jose A. , Faskhoodi Majid , Ali Lahmar Hakima , Mukisa Herman , Kadir Hanatu , Ibelegbu Charles , Pearson Warren , Ameuri Raouf , Sawchuk William 
Published: September 2019

Abstract
Enhanced oil recovery (EOR) is an economic way of producing the remaining oil out of previously produced Devonian Pinnacle Reefs in the Nisku Formation within the Bigoray area of Alberta. To maximize the recovery factor of the remaining oil, it was necessary to first characterize the geological structure, matrix reservoir properties, vugular porosity and the natural fracture network of these two carbonate reefs. This characterization model was then used for reservoir simulation history matching and production forecasting further discussed by (Rivero, 2019). With the enhanced resolution of a reprocessed 3D seismic volume, more accurate seismic interpretation was completed to better delineate the internal and external structure of the reefs. The petrophysical analysis and core interpretation showed that the two reefs could be divided into two zones; the bottom zone has low porosity and the upper zone has high porosity that was targeted in previous well completion schemes. These zones were easily picked on well logs and when using Seismic Ant Tracking attributes, were accurately interpreted within the seismic volume. With the framework of the geomodel developed, rock type, porosity, permeability and water saturation were interpolated within the reservoir. Because natural fractures in these carbonate reservoirs are known to be an important part of fluid movement, it was important to characterize the discrete fracture network. In one well, a borehole image successfully quantified the properties of the natural fracture network. The observed fracture density (5 fractures/m) suggested discreate fracture zones throughout the well which was also confirmed with core fracture mapping. As part of the geomodel, a discrete fracture model (DFN) was generated; Seismic Ant Tracking was used to interpolate the fracture intensity within the reservoir. In these Devonian Pinnacle Reefs, and in other reservoirs, before investing in an EOR scheme, it is critical for the operator to understand the geologic structure and the petrophysical characteristics of the reservoir in as much detail as possible. This paper demonstrates how log and seismic data that is up to 40 years old can be converted to modern data types and be used to characterize a reservoir in a way not possible before.
Towards Better Estimations of Rock Mechanical Properties Integrating Machine Learning Techniques for Application to Hydraulic Fracturing
Authors: Gong Yiwen , Mehana Mohamed , Xiong Fengyang , Xu Feng , El-Monier Ilham 
Published: September 2019

Abstract
Rock elastic moduli are one of the major perspectives for the hydraulic fracturing design. Among all of them, Young's modulus and Poisson's ratio essentially control fracture aperture for the proppant placement. The objective of this work is to predict the elastic moduli by applying data mining techniques as a comparison to the experimental measurements. We have collected attributes representing the pore structure, mineralogy and geomechanical characteristics. We implemented classification techniques such as k-means, hierarchical and PAM (partition around medoids). PAM results in more evenly-distributed clusters compared to the rest. Artificial Neural Network (ANN) is used for regression. We formulated two scenarios; firstly, all the data is grouped into one group and the other involves performing the regression on the clustered data. Interestingly, both scenarios yield acceptable results. The classification results could guide the fracturing operations where clusters with high brittleness, low anisotropy and high microfracture intensity could be identified as fracture candidates. Still the main limitation to unleash the machine learning capabilities in this domain is the data scarcity
A Unified Gas-Liquid Drift-Flux Model for Coupled Wellbore-Reservoir Simulation
Authors: Tang Hewei , Bailey William , Stone Terry , Killough John 
Published: September 2019

Abstract
Implementation of a drift-flux (DF) multiphase flow model within a fully-coupled wellbore-reservoir simulator is non-trivial and must adhere to a number of strict requirements in order to ensure numerical robustness and convergence. The existing DF model that can meet these requirements is only fully posed for upward flow from 2 degrees (from the horizontal) to vertical. The work attempts to extend the current DF model to a unified and numerically robust model that is applicable to all well inclinations. In order to achieve this objective, some 5805 experimentally measured data points from 22 sources as well as 13440 data points from the OLGA-S library are utilized to parameterize a new DF model – one that makes use of the accepted upward flow DF model and a new formulation extending this to horizontal and downward flow. The proposed model is compared against 2 existing DF models (also applicable to all inclinations) and is shown to have better, or equivalent, performance. More significantly, the model is also shown to be numerically smooth, continuous and stable for co-current flow when implemented in a fully implicitly coupled wellbore-reservoir simulator.
Fracture Cross-Flow Equilibrium in Simulation of Three-Phase Compositional Flows
Authors: Zidane Ali , Firoozabadi Abbas 
Published: September 2019

Abstract
We present an efficient numerical model for compositional three-phase flow in complex fractured media in 2D and 3D. The capillary effect is included in the simulations. The algorithm accounts for one aqueous phase and two hydrocarbon phases. CO2 is assumed to be soluble in the aqueous phase. We extend the fracture cross-flow equilibrium to three phases for the first time. The cubic plus association (CPA) equation of state describes the aqueous phase. To avoid small time steps in fracture elements we adopt an implicit time scheme discretization in the fractures. Capillary pressure gradients are computed at the element level. The phase fluxes are evaluated with the hybridized form of the mass conservative mixed finite element (MFE). A finite volume (FV) discretization is used in the mass balance equations in the fractures and the discontinuous Galerkin (DG) method is used in the matrix with an explicit time scheme. Pressure is implicit in the whole domain. Our algorithm accounts for different types of grids in 2D and in 3D.
When is There Too Much Fracture Intensity?
Authors: Cote Ashley , Cameron Neil , Grunberg Daniel 
Published: September 2019

Abstract
A distinct shift in wellbore fracture stimulation events has occurred within the Western Canadian Sedimentary Basin (WCSB) over the last 5 years. New designs, commonly referred to as "increased fracture intensity designs," are characterized by an increased number of fracture stages, decreased fracture spacing, and resulting increases in water and proppant required per stimulation. Existing technology applied in increased fracture intensity designs include: Open Hole Ball and Seat technology, Coil Activated sleeves, Plug and Perforating, as well as hybrid designs that combine several technologies.
Increased fracture intensity designs have contributed to improved production rates and increased reserves and, as a result, have quickly become the preferred approach to hydraulic fracture stimulation of the reservoir. Promising hydraulic fracture designs and decreased spacing designs run the risk of being applied broadly without discrimination.
Without proper retrospective or hindsight, there is a risk of over applying this new approach with false assurances of its success rates. It is therefore important to determine whether and at what point increasing fracture intensity generates diminishing returns.
This paper provides 3 retrospective case studies within the regions of the greater Montney and Cardium formations where increased fracture intensity designs have led to decreased well production as well as decreased reserve allocation. We further examine the various components of increased fracture intensity designs to pinpoint areas where design optimization may have prevented these outcomes.
Modeling and Optimization of Low Salinity Waterflood with Fines Transport
Authors: Gorucu Seyhan Emre , Dang Cuong , Nghiem Long , Shrivastava Vijay 
Published: September 2019

Abstract
After nearly thirty years of research and development, it is now commonly agreed that Low Salinity Waterflood (LSW) is an attractive enhanced oil recovery (EOR) method because of its incremental oil recovery performance, reasonable operating cost and low environmental impact compared to conventional waterflood and other EOR processes. From the past studies, LSW is known as a process that comprises many mechanisms, i.e. multiple ion exchanges, wettability alteration, complex geochemical reactions, and fines migration and deposition. However, most studies in the literature have only focused on a single recovery mechanism, with varying, sometimes contradictory conclusions. This paper presents: (1) a comprehensive model that takes into account all the different important physics in LSW, i.e. fines transport, geochemistry and wettability alteration; (2) validation with a core-flood experiment; and (3) field-scale optimization of LSW.
A model for fines transport has been developed and incorporated in an Equation-of-State compositional reservoir simulator with geochemistry and wettability alteration modeling. The proposed model is capable of accounting for complex transport phenomena of fines (clay) particles in porous media including fines deposition, entrainment, and plugging. The simulator also considers physical phenomena in the oil/rock/brine system such as aqueous chemical equilibrium, rate dependent mineral reactions, multiple ion exchanges, and relative permeability alteration due to wettability changes. Validations with a LSW core-flood experiment were carried out, which provide insights into the important mechanisms for the incremental oil recovery by LSW.
The proposed model shows good agreement in terms of oil recovery and pressure drop with a benchmark LSW core-flood experiment which was conducted with a non-polar oil and in which migration of clay particles and their plugging of pores were considered as the main recovery mechanism. It is shown that the proposed model can efficiently capture the important physics in LSW processes related to fines transport. The impact of formation damage during LSW can be efficiently evaluated using this model. Finally, an optimization workflow helps maximize the recovery factor of the LSW process.
To our knowledge, this paper describes one of the first LSW mechanistic models to capture the three principal mechanisms of LSW, i.e. fines transport, geochemistry, and wettability alteration. Excellent match with laboratory experiments and field-scale optimization reinforce validity of the model. The proposed workflow can be extended to other recovery methods such as Low-Salinity Polymer or Low-Salinity Alkali-Surfactant-Polymer.
Petroleum Engineering Enrollment: Past, Present and Future
Authors: Heinze Lloyd , Menouar Habib , Watson Marshall , Gamadi Talal 
Published: September 2019

Abstract
Objectives/Scope: Graduate and undergraduate petroleum engineering degrees and enrollments are presented. Causes and effects of huge changes in enrollment and degrees granted over the past sixty years are discussed. The impacts on the future of the petroleum industry’s available new engineers and sources of these talents are presented. Methods, Procedures, Process: United States petroleum engineering enrollments and degrees granted since the 1950’s have been collected from AIME (SPE’s mother institution) sources, SPE’s annual enrollment reports, and more recently surveys of the petroleum engineering department heads. Additional input from SPE’s standing Education and Accreditation Committee and Professionalism Committee are included. Approximately a dozen Colloquiums on Petroleum Engineering Education (CPEE) have been held over the past twenty-five years at locations in the US and other areas of the world. These CPEE discuss enrollment trends, job placement, industry needs and have resulted in significant advancements to petroleum engineering education. Over the last year information has been collected to include five years from non-US programs. Enrollment is compared to inflations adjusted oil prices. Lastly, a look at international petroleum programs as compared to SPE membership changes on a global basis. Results, Observations, Conclusions: This paper presents the following results, observations and conclusions: Petroleum Engineering enrollment and the resulting degrees granted are affected by oil and gas prices. These changes lag price by 2.5 years. The Recent peak in Bachelor of Science (BS) degrees granted 2550 (in 2017) are projected to drop 980 (in 2020). The pipeline to produce new engineers is four to five years long. As industry petroleum engineer requirement increases, it will take several years to increase the supply from previous conventional sources (programs/universities).
Impact of Chemical Osmosis on Brine Imbibition and Hydrocarbon Recovery in Liquid-Rich Shale Reservoirs
Authors: Torcuk Mehmet Ali , Uzun Ozan , Padin Anton , Kazemi Hossein 
Published: September 2019

Abstract
We present an assessment of the impact of low-salinity brine osmosis on oil recovery in liquid-rich shale reservoirs. The paper includes: (1) membrane behavior of shales when contacted by low-salinity brine, (2) numerical model of osmosis mass transport for low-salinity brine, and (3) enhanced oil recovery (EOR) potential of low-salinity osmosis in liquid-rich shale reservoirs.
Capillary osmosis causes low-salinity brine to be imbibed into the shale matrix; thus, forcing expulsion of oil from the rock matrix. This oil recovery process is described by a multi-component mass transport mathematical model consisting of advective and molecular transport of water molecules and dissolved ions. In the transport model, the activity-corrected diffusion of the brine solution is used to calculate the volume of brine imbibed into a shale core sample and the resulting expelled oil. We used the mathematical model to match oil recovery from two carefully designed brine-imbibition experiments conducted at Colorado School of Mines.
We have concluded that, in oil-wet shale reservoirs, low-salinity brine invasion of the rock matrix is by osmosis rather than capillary force. Thus, osmosis is the only imbibing force that drives the low salinity brine into the reservoir rock matrix. Furthermore, we believe brine osmosis can potentially enhance oil recovery by expelling oil out of the rock matrix and into the micro- and macro-fractures existing in the stimulated reservoir volume.
Separation Performance of Compact Axial Hydrocyclone for Water Pre-separation from Wellstream
Authors: Bai Chunlu , Liu Meili , Chen Jiaqing , Wang Chunsheng , Shang Chao , Zhang Ming 
Published: September 2019

Abstract
Efficient and compact separation technology is in urgent need for many oilfield exploitations because of increasing water cut and strict discharge regulations. A compact axial hydrocyclone is presented to pre-separate water from the wellstream. Experimental investigation was carried out to qualify its performance. A test loop is designed to perform experimental investigations. The flow loop is fabricated to manipulate and control various operational variables, such as the oil/water mixture flow rate (0.5-2 m3/h), the oil droplet size, and the water-to-oil ratio (65/35 to 100/0). A combination of venturi tube and static mixer is used to mix oil/water mixture. Dehydration rate and oil concentration at water outlet are used to evaluate the oil/water separation performance. A series of experiments have been carried out to test the performance of the novel hydrocyclone. Inlet parameters, including inlet flow rate, water cut, droplet size and split ratio, have been evaluated. Inlet flow rate, water cut, and droplet size have significant effects on the separation performance. When the oil concentration in the water outlet is controlled to be less than 1,000 ppm, a maximum dehydration rate of 70% can be obtained. The compact axial hydrocyclone exhibits high separation performance and reliability for a wide range of operating conditions. A stable oil core without vortex oscillations is observed. This effect, combined with the low pressure drop, indicates a stable swirl with low turbulence, which enables a higher capacity of the compact axial hydrocyclone compared to traditional hydrocyclone.