bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling of Viscous Displacement in Dual-Porosity Naturally Fractured Reservoirs: Application to Surfactant Enhanced Oil Recovery
Authors: Kiani Mojtaba , Alamdari Baharak B. , Kazemi Hossein 
Published: June 2014

Abstract
Surfactant-enhanced oil recovery (EOR) in fracture-dominated naturally fractured reservoirs (NFR) and very low-permeability Bakken type reservoirs is less known. Therefore, to predict its performance, improvement of the reservoir simulation tools is necessary to account for the surfactant flow mechanisms as much as possible. We present an improved dual-porosity (DP) numerical simulation model and algorithm in which matrix-fracture fluid transfer function was enhanced by implementing a proper viscous displacement mechanism. This mechanism was added to the existed fluid expansion, gravity drainage, and capillary pressure mechanisms. Current DP reservoir simulators generally do not account for the viscous displacement mechanism. To validate both the accuracy and efficacy of the improved model, results were compared with the results from a variable permeability-porosity, single-continuum, fine-grid model.
Simulation results of improved model were in agreement with the results of the fine-grid model as the reference case. In a one-dimensional numerical model, water flood cumulative oil production increased about 5% compared to the conventional DP model. Also, incremental oil production increased over 5% for 1 to 2 wt% surfactant concentrations. Similar results were obtained in multi-dimensional numerical models. In a representative matrix block, the water flood oil production rate started at 0.25 bbl/day in improved model compared to 0.053 bbl/day in conventional DP model. This rate was 0.124 bbl/day versus 0.03 bbl/day at the start of chemical injection. The improved model is computationally very efficient and is much faster than the fine-grid model.
For a practical application, the improved model was used to design and assess the viability of an EOR pilot-test using a single-well, multiple-completion protocol in a fractured carbonate reservoir. This reservoir has a matrix permeability of 10 md and matrix porosity of 0.05, and fracture permeability of 10,000 md. Similar result was obtained using improved and fine-grid models. Also sensitivity analysis was performed on fracture spacing of 5 to 20 ft. We found that smaller matrix blocks are affected more by viscous displacement.
Transport of Nanogel through Porous Media and Its Resistance to Water Flow
Authors: Almohsin Ayman , Bai Baojun , Imqam Abdulmohsin , Wei Mingzhen , Kang Wangli , Delshad Mojdeh , Sepehrnoori Kamy 
Published: June 2014

Abstract
The application of nanoparticles in enhanced oil recovery (EOR) continues to gain attention in the oil industry due to its apparent potential. However, previous studies have focused on the evaluation of stiff particles, such as silica and aluminum oxide. In this paper, we present our experimental results of deformable nanoparticle transport behavior through porous media. Nanogel particles with sizes ranging from 100–285 nm were used to represent deformable nanoparticles. Core flooding tests were run using sandstone cores with water permeabilities ranging from 42 to 1,038 mD. We investigated the effects of the permeability, particle concentration, particle deformability, and flow rate on the particle propagation, resistance factor, and residual resistance factor (permeability reduction factor). The results show that the resistance factor ranged from 5 to 14 for rocks with permeabilities higher than 311 mD, indicating that the nanoparticles were able to transport easily through these rocks. However, the resistance increased to 383 when the permeability was as low as 41.2 mD, indicating that the nanogel could not penetrate the rock easily. After placing the particles, brine was injected at different flow rates. The results indicate that the nanoparticles effectively reduced the permeability of the rocks with the original permeabilities of 143 to 555.4 mD, but the residual resistance factor of the high-permeability rock (1,038 mD) was relatively small, ranging from 2.67 to 4.39. The resistance factor and residual resistance factor increased with the particle concentration and decreased with the flow rate, and both factors can be well fitted using power law equations as a function of velocity. The nanogel adsorption layer thickness decreased with the shear rate.
Estimation of Oil Production Rates in Reservoirs Exposed to Focused Vibrational Energy
Authors: Jeong Chanseok , Kallivokas Loukas F. , Huh Chun , Lake Larry W. 
Published: June 2014

Abstract
Elastic wave-based enhanced oil recovery (EOR) is being investigated as a potential EOR method, since strong wave motions within an oil reservoir - induced by earthquakes or artificially generated vibrations - have been reported to improve the production rate of remaining oil from existing oil fields. To date, there are few theoretical studies on estimating how much bypassed oil within an oil reservoir could be mobilized by such vibrational stimulation. To fill this gap, this paper presents a numerical method to estimate the extent to which the bypassed oil is mobilized from low to high permeability reservoir areas, within a heterogeneous reservoir, via wave-induced cross-flow oscillation at the interface between the two reservoir permeability areas.
This work uses the finite element method to numerically obtain the pore fluid wave motion within a one-dimensional fluid-saturated porous permeable elastic solid medium embedded in a non-permeable elastic semi-infinite solid. To estimate the net volume of mobilized oil from the low to the high permeability areas, a fluid flow hysteresis hypothesis is adopted to describe the behavior at the interface between the two areas. Accordingly, the fluid that is moving from the low to the high permeability areas is assumed to transport a greater volume of oil than the fluid moving in the opposite direction.
The numerical experiments were conducted by using a prototype heterogeneous oil reservoir model, subjected to ground surface dynamic loading operating at low frequencies (1 to 20 Hz). The numerical results suggest that a substantial amount of oil could be mobilized via the elastic wave stimulation. It is also observed that certain excitation frequencies are more effective than others in mobilizing the remaining oil. We remark that these amplification frequencies depend on the formation's elastic properties.
The numerical simulations show that wave-based mobilization of bypassed oil in a heterogeneous oil reservoir is feasible, especially when combined with another EOR method, such as wettability alteration by low-concentration surfactant injection. The extension of this research into a more realistic three-dimensional reservoir model would help determine the optimal locations and frequencies of wave sources.
Right-Sizing the Jay/LEC Field – Commercial 30 Year EOR Project
Authors: Meister Travis , Valenti Nick , Geiger Paul , Townsend Mark 
Published: June 2014

Abstract
Major oil field facilities are designed to optimize on economic performance, which in turn is strongly driven by reserves and peak plateau production rates. However, at late-life conditions these major fields are producing at levels that may no longer merit elaborate facilities and accompanying operating costs. This point was reached in 2008 for the Jay/LEC field (referred to as the Jay field in this paper) that straddles the Florida/Alabama state line, with the field office located 40 miles north of Pensacola in Santa Rosa County, Florida.
A Novel Method of Forecasting CO2 Flood Performance for Various WAG Injection Schemes by Analyzing Injection Pulses
Authors: Liu Shunhua , Sahni Vinay , Hsu Chia-Fu 
Published: June 2014

Abstract
This paper presents a new method for generating dimensionless CO2 flood forecast prototypes for various injection schemes from an existing prototype. Given an existing prototype, the method described in this paper can predict an appropriate prototype for an alternating injection schedule. This methodology enables engineers to quickly generate forecast prototypes by analyzing the oil/gas production response from breaking down existing prototypes (developed either from simulation or from analog field performance) into injected CO2 pulses. A Microsoft Excel with VBA program (PULSER) based on this methodology has been successfully utilized to generate the prototypes for the fluid streams forecast of several West Texas/New Mexico CO2 flooding projects. When compared to reservoir simulation, the Pulse method is much faster in generating new prototypes and more flexible in accomodating different injection scenarios. The results from this method, full field simulation, and blind testing actual field data are remarkably consistent.
Negative Flash for Calculating the Intersecting Key Tie-lines in Multicomponent Gas Injection
Authors: Yan Wei , Michelsen Michael L. , Stenby Erling H. 
Published: June 2014

Abstract
Gas injection is a widely used enhanced oil recovery method and its application is expected to increase due to the high oil price and the need for sequestering carbon dioxide. In order to build a method of characteristics (MOC) solution to a two-phase gas injection system, we need to construct the composition path from the injection gas to the initial oil where all the intersecting key tie-lines must be identified. Calculation of these intersecting tie-lines requires a series of special negative flashes, which allow not only phase fractions outside the physical interval [0, 1] but also negative feed compositions. The phase compositions from one negative flash are used to recombine the feed for the next negative flash. Despite the apparent complexity due to multicomponent equilibrium and transport, for pure component gas injection, negative flash and elimination of components can be performed in an alternating manner. In particular, if the K-values are constant, there exists a simple feature that the vapor fraction roots (β-roots) for the Rachford-Rice equation for the initial oil are the roots to be found in all the negative flashes involved. This leads to a simple and well-structured algorithm for the solution at constant K-values. A unique problem with pure component gas injection is that there could be two possible roots in the β-interval of interest. But if the component to be eliminated is left with an infinitesimal amount, only one of them can still give non-negative phase compositions and thus should be selected. For multicomponent gas injection at constant K-values, we further prove that in addition to the invariant β-roots in the solution procedure, the λ-values for constructing the feeds are simply the vapor phase fraction roots for the injection gas. By solving two negative flashes for the initial oil and the injection gas, we can readily determine all the intersecting tie-lines at constant K-values.
A Novel, Field-representative Enhanced Oil Recovery Coreflood Method
Authors: Gupta Robin , Lu Pengbo , Glotzbach Rodney , Hehmeyer Owen 
Published: June 2014

Abstract
This study describes a new method that can improve laboratory determination of enhanced oil recovery (EOR) potential for a test fluid relative to a base fluid. The new method uses a modified steady-state fractional flow method to measure the shift in oil saturation in a rock at an intermediate fractional flow when changing from a base brine to a test EOR brine(s). This study uses fractional flow analysis and simulations to illustrate the new method and compare with the conventional unsteady-state approach. Through case studies, this work demonstrates that the conventional unsteady-state approach can under or overestimate EOR brine performance due to poor test design or limitations of the conventional method. The proposed method addresses these limitations. The study also discusses how to determine optimal values of fractional flow and total flow rate, both of which are critical test parameters for the new method.
Improving Sweep Efficiency In An Underpressured Naturally Fractured Reservoir
Authors: Montoya J. M , Sandoval R , Vargas A , Cabrera F. C. , Romero J. L. , Muñiz G 
Published: June 2014

Abstract
The Guando field is a late Cretaceous sandstone with two distinct reservoirs with total gross thickness of approximately 1300 feet. Discovered in 2000, the field is Colombia's largest oil discovery since the mid 1980's. Due to the low initial reservoir pressure, water injection began almost simultaneously with field development. Water is injected selectively into the main reservoir's main sands in order to optimize the distribution of injected water. However, oil recovery efficiency is challenged by reservoir heterogeneity, including natural fractures.
The first polymer gel conformance application in Colombia was implemented in 2008 in an effort to improve waterflood sweep efficiency. The objective of the gel treatments was to reduce the permeability in the most conductive natural fractures of the lower layer, ARIN formation. The conformance pilot included two non-adjacent patterns. Initially, the design team considered isolating the upper reservoirs and treating only the lower reservoirs. The treatment designs included several stages of varying gel concentrations and injection rates, which were modified in the course of each treatment application based on surface pressure response.
Post treatment oil response occurred within approximately two months and payout was achieved in less than ten months, driving new candidate selection and treatment in 2013. The paper will discuss the reservoir diagnostics that led to the selection of polymer gel as the most effective solution to severe water channeling. Also, we will present plans for additional gel treatments with an emphasis on cost reduction and improved treatment designs.
Polymer gels have been successfully applied in naturally fractured reservoirs for almost two decades, however, reservoir characterization tools continue to evolve, providing more precise diagnostics that offer improved conformance treatment designs. This case history will provide an updated framework for operators considering chemical sweep improvement technologies as part of an integrated field management strategy.
Long-Term Linear Flow Analysis: Finding Infill Sweet Spots in Underperforming Oil and Gas Fields
Authors: Stright D. H. , Bottjer R. J. 
Published: June 2014

Abstract
A case study will highlight the redevelopment of the Hornbuckle Sussex Field in Wyoming. After discovery in 1984 this oil field was developed on primary production with hydraulically fractured vertical wells. Following an initial steep decline in production the wells exhibit late time modest declines at marginally economic rates. In 2005, Hornbuckle field was generally believed to be depleted on primary production and lOR was not considered to be an option because of failed or underperforming waterfloods in neighboring fields.
Production analysis indicated the presence of long-term linear flow from Hornbuckle wells lasting more than 15 years. This flow regime indicates the presence of geologically-controlled high aspect ratio drainage volumes related to permeability anisotropy/connectivity issues. This is an inefficient drainage process which can result in low recovery factors and lead to further opportunities for infill drilling.
Geological and engineering studies were performed to investigate the feasibility of horizontal well drilling in this field. The paper will show the data mining aspects which identified the opportunity as well as the more detailed analysis that ultimately lead to horizontal well drilling and multi-stage fracturing beginning in 2006. Finally, available horizontal well production performance will be reviewed. Since 2006, field oil production rate has increased more than 25-fold and cumulative oil production has doubled. Redevelopment with horizontal wells is ongoing. The net result is a clear methodology to identify underperforming fields and assess opportunities for redevelopment.
Impact of Salt Diffusion on Low-Salinity Enhanced Oil Recovery
Authors: Brodie James , Jerauld Gary 
Published: June 2014

Abstract
Low-salinity water flooding is an emerging EOR technique that has yielded significant incremental oil in core floods and single- and inter-well trials. Because low-salinity water flooding involves reducing salinity to a low level, of the order of 1000 ppm, there is a risk that its efficiency could be reduced by mixing between injected low-salinity water and high-salinity in situ water held in shales. This risk is more significant when the in situ salinity is very high and the amount of water held in shale is large, as is the case in some reservoirs found in deep-water depositional environments.
To investigate the effect of salt diffusion on low-salinity EOR, low- and normal-salinity (sea water) water floods were simulated in fine-scale, 2D models of deep-water reservoirs incorporating dispersive and diffusive mixing of injected and in situ water and the wettability change caused by low salinity. In the model, dispersion predominates in sandstone, whereas diffusion controls the transport of salt ions within shale. The dispersivity and diffusion coefficients are based on published data.
The simulation results show that low-salinity water-flooding of thin (&lt;2.4m thick) sand layers sandwiched between thick shales is vulnerable to salt diffusion at practical flood rates when the in situ salinity is high (e.g. ≥100,000 ppm). In such layers, diffusion can reduce low-salinity EOR by more than 90%. In the reservoir models we studied, diffusion can reduce the overall low-salinity EOR to 60 – 95% of the value calculated when diffusion is neglected. The adverse effect of diffusion increases as the average sand layer thickness decreases. In thick, channel sands, salt diffusion has only a small effect. Apart from reservoir description, the most important controls on the effect of salt diffusion are intra-reservoir shale diffusivity and in situ salinity.
The simulation results were used to calibrate a simple model for rapidly screening stratified reservoirs. The screening model calculates a ‘diffusion recovery factor (RF) multiplier’ which can be used to discount conventional low-salinity EOR predictions that neglect salt diffusion. The screening model matches simulation data to within 14% RMSE.
Low Salinity Waterflooding at West Salym: Laboratory Experiments and Field Forecasts
Authors: Suijkerbuijk B. M. , Sorop T. G. , Parker A. R. , Masalmeh S. K. , Chmuzh I. V. , Karpan V. M. , Volokitin Y. E. , Skripkin A. G. 
Published: June 2014

Abstract
Low Salinity Waterflooding (LSF) is a rapidly emerging IOR/EOR technology that improves oil recovery by lowering the injection water salinity. A membrane-based desalination process provides additional advantages such as reduction of souring, scaling and it can prevent injectivity decline. Proper screening of LSF for a particular field requires performing laboratory SCAL tests to (i) measure relative permeability curves to enable field-scale quantification of the LSF benefits by modeling and (ii) de-risk the potential of formation damage through clay swelling and deflocculation.
Salym Petroleum Development (SPD; JV Shell/GazPromNeft) is actively looking into IOR/EOR methods to increase the water flood recovery factor. While ASP is being matured as the main EOR option, several LSF laboratory tests have been performed recently to assess the potential of this technique for West Salym. A key LSF enabler in the area is the presence of large, relatively low-saline aquifers in the vicinity of the field, which can serve as a plentiful source of low salinity (LS) injection brine.
This study focuses on the initial Salym LSF SCAL tests performed at reservoir conditions, using representative reservoir core and crude oil, with synthetic brines that reflect the formation and injection water compositions accurately. The experiments comprised a suite of Amott and coreflood tests, following the internal Shell LSF protocol. The tests clearly show a positive LSF effect, with additional oil produced in absence of formation damage. The data indicates that LSF causes a shift in wettability towards a more water-wet behavior, and results in a reduction of Sorw. Upscaling the core flood results to field scale indicated that incremental recoveries within the life time of the field could be 1.7% of oil initially in place (OIIP) in tertiary mode, while a secondary mode LSF scheme would have increased the oil recovery over the same time by almost 4% of OIIP.
Streamline-based Transport Tomography Using Novel Tracer Technologies
Authors: Kam D. , Datta-Gupta A. 
Published: June 2014

Abstract
Traditional history matching involves calibration of reservoir models using well response such as production or tracer data aggregated over multiple producing intervals. With the advent of novel tracer technologies, we can now obtain distributed water or tracer arrival time information along the length of horizontal or vertical wellbores. This provides significantly improved flow resolution for detailed reservoir characterization through inversion of distributed water or tracer arrival times in a manner analogous to travel tomography in Geophysics.
In this paper, we present an efficient approach to incorporate novel tracer surveillance data and distributed water arrival time information during history matching of high resolution reservoir models. Our approach relies on a novel streamline-based workflow that analytically computes the sensitivity of the arrival time with respect to reservoir heterogeneity, specifically porosity and permeability variations. The sensitivities relate the changes in arrival time to small perturbations in reservoir properties and can be obtained efficiently using the streamline-based approach with a single flow simulation. This makes the approach particularly well-suited for high resolution reservoir characterization. Finally, the sensitivities are used in conjunction with an iterative inversion algorithm to update the reservoir models using existing and proven techniques from seismic tomography.
The power and utility of our proposed approach is demonstrated using both synthetic and field examples. These include the SPE benchmark Brugge field case and a tracer test at the Hill Air Force Base, Utah. Compared to traditional history matching techniques, the proposed tomographic approach is shown to result in improved resolution of heterogeneity through matching of water arrival time at individual completions in addition to the aggregated well production response. This results in improved performance predictions and better identification of bypassed oil for infill targeting and EOR applications.