bluuebunny/crossref_metadata_2025_split huggingface dataset:
Steam Injection in Tight Oil Reservoir
Authors: Ross T. S. , Rahnema H. , Nwachukwu C. , Alebiosu O. , Shabani B. 
Published: March 2018

Abstract
Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.
The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).
A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
Wettability Alteration and Flow Coupling in Gas Flooding of Asphaltenic Reservoirs
Authors: Abouie Ali , Tagavifar Mohsen , Sepehrnoori Kamy 
Published: March 2018

Abstract
Mixing of an asphaltenic oil with light gases (e.g., CO2) and/or depressurizing such a crude oil can lead to phase separation in which a second liquid phase L2 -highly concentrated in asphaltene- is formed. Asphaltene may precipitate or deposit out of the second liquid phase. This causes formation damage, wettability alteration, and recovery reduction. While asphaltene phase behavior have been studied under static conditions (where equilibrium is imposed), the behavior of asphaltene under dynamic flow conditions is relatively unexplored. Here, we investigate the coupling of asphaltene phase behavior and flow in porous media. As such, two asphaltenic crudes are characterized using the PC-SAFT equation-of- state. The fluid models were then used to fit the experimental asphaltene deposition data under static conditions. Subsequently, asphaltene flow and deposition was studied during miscible gas flooding where four phases (water, oil L1, gas, and second liquid L2) are present. Our results show that (i) wettability alteration increases the mixing zone and decreases both the displacement and sweep efficiencies; (ii) asphaltene deposition, hence wettability alteration and formation damage are maximal near the producer.
Deployment of Large Scale Surfactant Manufacture for EOR Projects
Authors: Barnes J. R. , Regalado D. Perez , Crom L. A. , Doll M. J. , King T. E. , Covin D. Y. , Crawford J. N. , Kunkeler P. J. 
Published: March 2018

Abstract
Surfactant quantities increase dramatically moving from small field tests (e.g. single well tests) to multiwell pilots to full scale EOR projects. This paper is a companion paper to SPE-190453, presented at the SPE conference in Oman in March 2018, and shows how best practices from existing large-scale surfactant manufacture (for household and industrial applications) can be applied and adapted for manufacture and delivery of EOR surfactants as field projects are upscaled.
Surfactant concentrates can be viscous, making them difficult to pump and mix. This paper presents improved methods to manufacture and handle them. In addition, dilution of the concentrate in the field to the working (injected) formulation needs to be carried done in a manner which avoids the formation of viscous phases that are common with surfactants.
The main learnings from this paper are: For small field projects, it is usually advantageous to ship less concentrated products (e.g. ≤ 30% active matter, AM) as, for the small volumes involved, the advantages of ease of mixing and dilution in the field tend to outweigh the cost savings in transporting a highly concentrated product.An additive (viscosity modifier), applied during manufacture, reduces viscosity and improves handleability of highly concentrated products (e.g. ≥ 65% AM). This viscosity modifier is benign for sub-surface performance of the surfactant.For large projects, two strategies can be used to reduce logistics costs: Supply a concentrated product with viscosity modifier (to reduce the percentage of water shipped), and/orManufacture the product (or part of the product) in country/region and near the field.A realistic supply chain was used to estimate the logistics costs to transport low and high %AM products from a USA point of manufacture to an EOR project destination in South America. This calculation assumed an equal manufacturing cost for the low and high %AM products and transportation by 20 ton ISO-tanks, a standard bulk industry container. The transportation cost for the high %AM product is around 57% of the low %AM product. Additional logistics savings are achievable through manufacturing the product (or part of the product) in country/region, and the logistics cost for high %AM product manufactured near the field can be reduced to 33% of of that for the low %AM product manufactured in the USA.
More general learning for EOR projects are: Experience from the wider, bulk chemicals industry can be usefully applied for EOR projects.It is important to align surfactant manufacture/supply logistics with reservoir management and the field life plan as significant lead time is required for supply of large surfactant volumes.
Foaming Behavior of CO2-Soluble, Viscoelastic Surfactant in Homogenous Porous Media
Authors: Ramadhan Galang , Hirasaki George , Nguyen Quoc P. 
Published: March 2018

Abstract
Aqueous foam has been demonstrated through laboratory and field experiments to be a promising conformance control technique. This study explores the foaming behavior of a CO2-soluble, cationic, amine-based surfactant. A distinguishing feature of this surfactant is its ability to dissolve in supercritical CO2 and to form Wormlike Micelles (WLM) at elevated salinity. Presence of WLM led to an increase in viscosity of the aqueous surfactant solution. Our study investigates how the presence of WLM structures affect transient foam behavior in a homogenous porous media (sand pack).
Sand pack foam flooding experiments were performed with two aqueous phase salinities: low salinity (15 wt. % NaCl) associated with spherical-shaped micelle and high salinity (20 wt. % NaCl) associated with WLM. We compared the onset of strong foam propagation and foam apparent viscosity buildup rate between the two salinity cases. The effect of WLM presence in transient foam behavior was investigated for co-injection and water-alternating-gas (WAG) injection strategies. In all foam flooding experiments, the surfactant was delivered in the CO2 phase.
Strong foam was generated in all foam flooding experiments, with an apparent foam viscosity of at least 600 cp for co-injection and 200 cp for WAG floods after five total injected pore volumes. The observed strong foam indicated that the delivery of surfactant in the CO2 phase was successful and that the surfactant molecules partition to the water phase in the sand pack. In comparison to the low salinity cases, the high salinity foam floods associated with the presence of WLM led to better foam performance. We observed an earlier onset of strong foam propagation as well as a higher apparent viscosity buildup rate. Better foam performance at higher salinity may be attributed in large part to the presence of WLM structures in the foam liquid phase. Entanglement of these WLM structures may have led to in-situ viscosification of the foam liquid phase and an increase in disjoining pressure between foam films. Both phenomena may have reduced the rate of foam film coalescence.
WLM structures behave similarly to polymer molecules. Our study may offer evidence that WLM is a valid alternative to polymer as an additive to enhance foam conformance control performance. Some potential advantages of WLM over polymer include: Delivery of surfactant in the gas phase (to alleviate the injectivity issue typically associated with high viscosity polymer-surfactant solution), resistance to extreme temperature and salinity, and reversible shear degradation.
An Update on Full Field Implementation of Chemical Flooding in Daqing Oilfield, China, and Its Future
Authors: Yin Shize , Pu Hui , Zhou Shide 
Published: March 2018

Abstract
The implementation of chemical fooding such as polymer flooding and alkaline/surfactant/polymer (ASP) flooding in Daqing oilfield is presented in this paper. The annual crude oil production rate by chemical EOR in Daqing oilfield has been kept over 73.3 million barrels per year for 15 consecutive years. According to the actual field production data, the incremental oil recoveries by polymer flooding is over 10% OOIP and incremental oil recovery by ASP flooding is more than 20% OOIP over that of waterflooding. This paper discusses the progresses made in Daqing over the last 30 years, including crucial application strategies, optimized design of surface facilities, field results, methods to solve technical challenges of chemical flooding, strategies to reduce cost for commercial-scale chemical EOR, and future development direction, especially future development plan for ASP. Four major lesssons are obtained for the best quality reservoirs defined as First Class oil layers in Daqing oilfield, in which polymer flooding has been completed. The existing problems are described for the medium and poor quality reservoirs defined as Second or Third Class, in which polymer flooding or ASP flooding is in progress, and the strategies are proposed, such as injection mode optimization, optimization of injection parameters, optimization of adjustment measures, optimization of well spacing, subdivision of pay zones, separate layer injection, optimization of slug combination, etc. This paper also proposes policy guidance for chemical flooding adjustment in Daqing oilfield in the coming years and provides references for chemical flooding production in other oilfields.
The Onset of Spontaneous Imbibition: How Irregular Fronts Influence Imbibition Rate and Scaling Groups
Authors: Føyen T. L. , Fernø M. A. , Brattekås B. 
Published: March 2018

Abstract
Spontaneous imbibition is a capillary dominated displacement process where a non-wetting fluid is displaced from a porous medium by the inflow of a more-wetting fluid. Spontaneous imbibition strongly impacts waterflood oil recovery in fractured reservoirs and is therefore widely studied, often using core scale experiments for predictions. Decades of core scale experiments have concluded that spontaneous imbibition occurs by a uniformly shaped saturation front and that the rate of imbibition scales with square root of time. We use emerging imaging techniques to study local flow patterns and present new experimental results where spontaneous imbibition deviates from this behavior.
The imbibition rate during early stages of spontaneous imbibition (the onset period) was sometimes observed to deviate from the square root of time behavior. The impact of the onset period on the imbibition process is, however, not well understood. In this work, the development of displacement fronts were visualized during the onset period, using twodimensional paperboard models and core plugs imaged using Positron Emission Tomography (PET-CT). The new experimental results provided insight on the dynamics during the initial spontaneous imbibition period. Controlled two-dimensional paperboard experiments demonstrated that restricted wetting phase flow through the surface exposed to water caused irregular saturation fronts and deviation from the square root of time behavior during the onset period. Local restriction of the wetting phase flow was observed during spontaneous imbibition in sandstone core plugs as a result of non-uniform wetting preference. The presence of nonuniform wetting resulted in unpredictable spontaneous imbibition behavior, with induction time (delayed imbibition start) and highly irregular fronts. Without imaging, the development of irregular saturation fronts cannot be observed locally; hence the effect cannot be accounted for, and the development of spontaneous imbibition in the core erroneously interpreted as a corescale wettability effect. This underlines the undeniable need for a homogenous wettability preference through the porous medium when performing laboratory spontaneous imbibition measurements. Our observations of non-uniform wetting preference will affect Darcy-scale wettability measurements, scaling and modeling. We argue that great care must be taken when preparing core plugs for spontaneous imbibition, to avoid experimental artifacts.
CO2 Foam Field Pilot Test in Sandstone Reservoir: Complete Analysis of Foam Pilot Response
Authors: Patil P. D. , Knight T. , Katiyar A. , Vanderwal P. , Scherlin J. , Rozowski P. , Ibrahim M. , Sridhar G. B. , Nguyen Q. P. 
Published: March 2018

Abstract
This paper summarizes the overall response from the CO2-foam injection in the Salt Creek field, Natrona County, Wyoming. Conformance control of CO2 by creating foam between supercritical CO2 and brine to improve the sweep efficiency is documented in this paper. The foam was implemented in an inverted fivespot pattern in the Salt Creek field where the second Wall Creek (WC2) sandstone formation is the primary producing interval, with a net thickness of about 80 ft and at a depth of approximately 2,200 ft. The initial phase of the foam pilot design involving identifying the pilot area, performing coreflood experiments, performaing dynamic reservoir simulation for history match, and forecasting with foam have been documented in the literature. As a part of the foam pilot monitoring, a gas tracer study was performed before and after the injection of foam in the reservoir. The initial planning, monitoring, and part of foam response is covered in earlier publications. The last surfactant injection in the field was in June 2016. This paper provides the complete analysis of the results from the foam pilot. The foam pilot was successful in demonstrating the deeper conformance control and improvement in sweep efficiency, which resulted in 25,000 bbl of incremental oil. Also overall, a 22% decrease in CO2 injection amount is realized due to better utilization of CO2 compared to the baseline.
Use of Cross-Linked Polymer Systems to Improve Volumetric Sweep Efficiency and Alternative Full Field Development Strategy for a Mature Waterflooding Optimization Processes - Dina Cretaceous Field Case
Authors: Leon J. M , Izadi M. , Castillo A. , Zapata J. F. , Chaparro C. , Jimenez J. , Vicente S. E. , Castro R. 
Published: March 2018

Abstract
The Dina Cretaceous field, operated by Ecopetrol S.A., is located in the Upper Magdalena Valley (UMV) Basin in Colombia. The field discovered in 1969, reaching maximum primary oil rate of 6,500 BOPD in May 1980. Secondary recovery mainly by peripheral water injection started in 1986, achieving a maximum production of 9,850 BOPD in January 1988. Subsequently, water production has increased rapidly accompanied by declining oil production, due primarily to reservoir heterogeneity and an unfavorable mobility ratio. The oil recovery factor as of October 2017, as a percentage of OOIP, is estimated to be approximately 33% at a current water cut of about 97%.
Ecopetrol S.A in 2009, began to look for new development strategies that would allow optimizing the oil recovery for this asset. Several IOR/EOR technologies were screened to reduce water production and increase sweep efficiency. Polymer gels ("Conformance treatments"), polymer flooding and cross-linked polymer also known as Colloidal Dispersion Gels (CDG) are some of the technologies most commonly used during the last few decades for this purpos. Based on screening study, detailed production and injection data analysis, water channeling, reservoir heterogeneity, adverse mobility ratio, laboratory evaluation and simulation results, the cross-linked polymer systems (CDG) were implemented in four patterns between 2011 and 2015. This would allow to increase the volumetric sweeping efficiency both for mobility control, in-depth conformance control and leading to viable project both technically and economically.
This paper presents the implementation and results of the injection of cross-linked polymer systems in the Dina Cretaceous field. A summary of the maturation process is presented, from conceptual design, experimental evaluation, engineering analysis, numerical simulation, pilot execution, process monitoring and field expansion strategy, as well as the results obtained in the pilot.
The results of the pilot were satisfactory both technically and economically and lead to a new development plan for the field. This new plant is focused on the optimization of the waterflood, pattern reconfiguration, infill drilling, selective injection, and improving the sweep efficiency through the injection of cross-linked polymer across the field in 11 more patterns.
Application of Surfactants in Shale Chemical EOR at High Temperatures
Authors: Zeng Tongzhou , S. Miller Chammi , Mohanty Kishore 
Published: March 2018

Abstract
The goal of this work is to develop surfactant systems that can improve oil flow from shale wells after fracturing or re-fracturing. Surfactants can reduce oil-water interfacial tension and wettability of the shale, which in turn can improve water imbibition, increase oil relative permeability and reduce water blockage at the matrix-fracture interface. Temperature in typical shale reservoirs are high and the surfactants need to be aqueous stable to be effective in these treatments. Mixing two surfactants often gives higher aqueous stability than those of the single surfactants. A large number of surfactants (anionic, non-ionic and cationic) and their blends were studied for aqueous stability, contact angle and spontaneous imbibition. Seven single surfactants and nine surfactant blends were found to be stable in both high and low salinity brines at 125 °C. All aqueous stable blends changed wettability of oil-wet shale to preferentially water-wet in both high and low salinity brines. Seven single surfactants and five surfactant blends were tested for imbibition. Surfactant solutions improved water imbibition to the extent of 20% PV. Surfactant blends improved imbibition more than the single surfactants. Imbibition in cores reached a plateau in about 3 days. Surfactant blends have the potential to be used in low salinity fracturing or refracturing fluids to stimulate shale wells.
A New Mathematical Model of Solvent - SAGD Process - Importance of Heat and Mass Transfer
Authors: Zargar Zeinab , Ali S. M. 
Published: March 2018

Abstract
The current in situ exploitation of oil sands in Alberta employs steam-based recovery methods, which are energy-intensive. A few companies are adding solvent to steam aiming to reduce steam requirements. The mechanism of oil recovery by steam with added solvent is not clear. Over the years, on several occasions- as at the present time- the oil industry has resorted to the use of solvents with steam in thermal recovery operations. The past trials with solvent were short-lived in view of the cost of solvents as well as the lack of success. Given the controversy regarding the use of solvents with steam, this work is intended to explain whether solvent injection with steam increases oil recovery or not.
In this work, a new analytical model is developed for describing the solvent-SAGD performance based on the combination of an overall solvent mass balance, heat balance and volumetric oil displacement and Darcy's oil rate using a mixture viscosity model as a function of temperature and solvent concentration ahead of front which satisfy the equilibrium in the system.
The objectives of this work are to predict: vapour-steam chamber growth, oil production rate, solvent production rate, solvent loss (or solvent retention) rate, and the effect of solvent type and concentration on the solvent-SAGD process. The results show that the rate of solvent retention increases over time, while the production rates of solvent and bitumen decrease.
The efficiency of this process is evaluated using Cumulative Steam-Oil Ratio (CSOR) and cumulative solvent-oil ratio, which permits a comparison of the efficiency of SAGD and solvent-SAGD processes for different solvents. On the whole, the results of this approach give a better understanding of the mechanism of oil production during the solvent-SAGD process by interconnecting vapour chamber conditions and the conditions of heated and diluted oil ahead of the interface.
Data Fit Comparison of Mixture Item Response Theory Models and Traditional Models
Authors: Yalçın Seher 
Published: March 2018

The
purpose of this study is to determine the best IRT model [Rasch, 2PL, 3PL, 4PL
and mixed IRT (2 and 3PL)] for the science and technology subtest of the
Transition from Basic Education to Secondary Education (TEOG) exam, which is carried
out at national level, it is also aimed to predict the item parameters under
the best model. This study is a basic research as it contributes to the
information production which is fundamental for test development theories. The
study group of the research is composed of 5000 students who were randomly
selected from students who participated in TEOG exam in 2015. The analyses were
carried out on 17 multiple choice items in TEOG science and technology subtest.
When model fit indices were evaluated, the MixIRT model with two parameters and three
latent classes was found to fit the data best. According to this model, when
the difficulties and discrimination averages of the items are taken into
account, it can be expressed that items are moderately difficult and discriminative for students in latent
class-1; the items are considerably easy and able to slightly distinguish the students in latent class-2; the items are difficult to
the students in the third latent class and they can slightly distinguish the
students in this group.