bluuebunny/crossref_metadata_2025_split huggingface dataset:
Interfacial Visco-Elasticity of Crude Oil - Brine: An Alternative EOR Mechanism in Smart Waterflooding
Authors: Alvarado Vladimir , Bidhendi Mehrnoosh Moradi , Garcia-Olvera Griselda , Morin Brendon , Oakey John S. 
Published: June 2014

Abstract
Injection of water with designed chemistry has been proposed as a novel enhanced-oil recovery (EOR) method, commonly referred to as low-salinity or smart waterflooding, among other names. The plethora of names encompasses a family of EOR methods that rely on modifying injection water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. The vast majority of the proposed mechanisms rely on rock-fluid interactions. In this work, we propose an alternative fluid-fluid interaction mechanism, i.e. an increase in crude oil-water interfacial visco-elasticity upon injection of designed brine as a suppressor of oil trapping by snap-off.
A crude oil from Wyoming was selected for its known interfacial response to water chemistry variation. Brines were prepared using analytic grade salts to test the effect of specific anions and cations. The ionic strength of brines was modified by dilution with deionized water to the desired salinity. A battery of experiments were performed to demonstrate the impact of dynamic interfacial viscoelasticity on recovery including double-wall ring interfacial rheometry, dilational rheology, direct visualization in microfluidic devices and coreflooding experiments in Berea sandstone cores.
Interfacial rheological characterization shows that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of what cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend upon specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off and sustains a more continuous oil phase. This effect was examined in coreflooding experiments using sodium sulfate brines. Corefloods were designed to prevent wettability alteration by maintaining a low temperature (25 °C) and short aging times. Geochemical analysis provided information on in situ water chemistry needed to establish a direct link between brine composition and oil displacement. Oil recovery and pressure responses were shown to directly correlate with interfacial elasticity, i.e. recovery factor is greater the larger the induced interfacial viscoelasticity.
Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can provide as an alternative and more complete explanation of low-salinity or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water chemistry processes and opens a new route to design EOR methods.
New Insights on the Effect of Oil Saturation on the Optimum Acid Injection Rate in Carbonate Acidizing
Authors: Kumar R. , He J. , Nasr-El-Din H. 
Published: June 2014

Abstract
The existence of an optimum injection rate for wormhole propagation and face dissolution at low injection rates during matrix acidizing are well established. However, little has been documented that describes how the presence of residual oil affects carbonate acidizing. This study demonstrates the impact of oil saturation on wormholing characteristics while acidizing field and outcrop cores under reservoir conditions (200°F). Knowledge of the effect of different saturation conditions on acid performance will contribute towards the design of more effective acid treatments.
Coreflood experiments at flow rates ranging from 0.5 to 20 cm3/min were performed to determine the optimum acid injection rate for wormhole propagation when acidizing homogeneous limestone reservoir cores, low permeability Indiana limestone cores, and homogeneous dolomite cores with dimensions 3 and 6 in. of length and 1.5 in. of diameter. The study involved acidizing cores saturated with water, oil, and waterflood residual oil using 15 wt% HCl. The viscosity of the crude oil used was 3.8 cp at 200°F. CT scans were used to characterize wormholes through the cores. The concentrations of the dissolved calcium and magnesium ions were measured using Inductively Coupled Plasma-Optical Emission Spectroscopy (ICP-OES) and the effluent samples were titrated to determine the concentration of the acid.
At injection rates 0.5 to 20 cm3/min, 15 wt% HCl was effective in creating wormholes with minimal branches for cores with residual oil (Sor=0.4-0.5). Compared to brine and oil saturated cores, waterflood residual oil cores took less acid volume to breakthrough. Additionally, the wormholing efficiency of regular acid improved with increased acid injection rates in the presence of residual oil. A decrease in acid pore volumes to breakthrough for oil saturated cores was noted at high acid injection rates, which could be attributed to viscous fingering of acid through oil. Unlike brine saturated and oil saturated cores, waterflood residual oil cores showed no face dissolution at low acid injection rates. Conclusions from this work will aid in the design of better acid jobs by highlighting the impact of oil saturation on the wormholing characteristics of acid while acidizing carbonate rocks.
Charge Control and Wettability Alteration at Solid-Liquid Interfaces
Authors: Mugele Frieder , Siretanu Igor , Kumar Naveen , Bera Bijoy , Wang Lei , de Ruiter Rielle , Maestro Armando , Duits Michel , van den Ende Dirk 
Published: June 2014

Abstract
Most solid surfaces acquire a finite surface charge upon exposure to aqueous environments due to desorption and/or adsorption of ionic species. The resulting electrostatic forces play a crucial role in many fields of science, including colloidal stability, self-assembly, wetting, and biophysics as well as technology. Enhanced oil recovery is an example of a large scale industrial process that hinges in many respects on these phenomena.
In this paper, we present a series of experiments illustrating fundamental aspects of low salinity water flooding in well-defined model systems. We show how pH and ion content of the water phase as well as the presence of model polar components (fatty acids) in the oil phase affect the wettability (i.e. contact angle distribution) of oil-water-rock systems. Specifically, we discuss high resolution atomic force microscopy (AFM) experiments demonstrating the preferential adsorption of multivalent cations to mineral surfaces such as mica and gibbsite. Cation adsorption leads to increased and in some cases reversed surface charge at the solid-liquid interface. In the case of charge reversal, the adsorption process can trigger a wetting transition from complete water wetting in ambient oil (i.e. zero water contact angle) in the absence to partial wetting in the presence of divalent cations. While already dramatic for pure alkanes as base oil, adding fatty acids to the oil phase enhances the effect of divalent ions on the oil-water-rock wettability even more. In this case, contact angle variations of more than 70° can be observed as a function of the salt concentration. This enhancement is caused by the deposition of a thin film of fatty acid on the solid surface. AFM as well as surface plasmon resonance spectroscopy measurement in a microfluidic continuous flow cell directly demonstrate that adsorbed Ca+ ions promote secondary adsorption of acidic components from the oil phase.
The combination of the effects discussed provides a rational scenario explaining many aspects of the success of low salinity water flooding.
Polymer Flooding of a Heavy Oil Reservoir with an Active Aquifer
Authors: Li Zhitao , Delshad Mojdeh , Lotfollahi Mohammad , Koh Heesong , Luo Haishan , Chang Harry L. , Zhang Jieyuan , Dempsey Peter , Lucas-Clements Charles , Brennan Barny 
Published: June 2014

Abstract
In recent years, polymer flooding of heavy oil has been extensively studied in laboratories and successfully applied in several fields. This paper reports the laboratory corefloods, development of mechanistic models, and simulation studies of polymer flooding in a heavy oil reservoir with active aquifer influxes.
Bentley Field, operated by Xcite Energy Resources, is located on the UK Continental Shelf. Flow tests confirmed the existence of a large, active bottom aquifer which may cause polymer loss and decrease the economic attractiveness of polymer flooding. To analyze the impact of the aquifer on oil recovery efficiency, a reservoir simulation model was set up. Several development scenarios have been simulated for the optimization of development strategy. Conventional thinking, based on previously accepted EOR screening criteria, would be that the oil viscosity (approximately 1500 cp) exceeds the economic and technical limit of oil viscosity for polymer flooding. However, this paper demonstrates that the limit for effective polymer flooding can be extended to considerably higher viscosity oils. To validate the applicability of polymer flooding, two laboratory experiments were conducted with two different high permeability sandpacks. Due to the unconsolidated nature of the Bentley formation no cores were available. Waterflooding was stopped when water cut reached 90% and up to that point, less than 25% of oil in place had been recovered. However, the remaining oil saturations after both tertiary polymer corefloods achieved around a 5% level. We investigated the recovery mechanisms and developed a mechanistic model to match the laboratory observations.
Simulation results show that for this heavy oil field with an active aquifer, polymer flooding economics can be improved by optimizing well locations, number of horizontal wells, polymer injection time, etc. In history matching coreflood experiments, two oil saturation reduction mechanisms were considered: (1) viscous polymer solution reduces viscous fingering and channeling effects especially in the heavy oil displacement process and also reduces remaining oil saturation after waterflooding; (2) remaining oil can be mobilized by viscoelastic properties of synthetic polymer solutions. Both mechanisms were considered in the simulation study where a favorable match of oil recovery and pressure drop was obtained.
In this paper, polymer flooding is shown as a viable technology in a heavy oil reservoir, despite the highly unfavorable mobility ratio and strong aquifer influxes. Considering the diminishing conventional oil reserves, polymer flooding provides a non-thermal approach for producing heavy oil reserves that may be particularly attractive in an offshore environment, compared to thermal techniques.
New Experiments and Models for Conformance Control Microgels
Authors: Goudarzi Ali , Almohsin Ayman , Varavei Abdoljalil , Delshad Mojdeh , Bai Baojun , Sepehrnoori Kamy 
Published: June 2014

Abstract
Water management in mature waterflooded reservoirs is a top priority to push more oil out and control water production. Excess water production through fractures and high permeability thief zones is a growing concern for sweep efficiency and oil production. Gel treatment has been applied widely to plug thief zones and reduce excess water production to improve macroscopic sweep efficiency. Field studies demonstrated that gel treatments can be applied successfully in mature and fractured reservoirs to reduce unwanted fluid production to lower the operating cost causing premature well abandonment.
The primary objectives of this work are to conduct laboratory work to understand the transport and propagation of microgel and develop conformance control reservoir simulator to help in screening oil reservoir targets for effective particle gel applications to improve sweep efficiency and reduce the water production. These microgels can be injected as a suspension in water into an injection well. Many experiments were performed to understand the transport mechanism of microgels through porous media and to identify the control variables. The lab data include oil recovery, water cut, resistance factor, residual resistance factor, oil viscosities, gel concentrations, salinity, gel rheology, and gel strength. The success of gel treatment depends on the magnitude of permeability reduction and flow diversion.
We have developed correlations for resistance factor, residual resistance factor, and apparent viscosity as a function of gel strength, gel concentration, rock permeability, salinity, and flow rate. The models are validated against lab measurements and implemented into a reservoir simulator called UTGEL. Gel properties such as rheology and adsorption are also investigated.
The mechanistic models and numerical tool developed will help to select future conformance control candidates for a given field and to optimize the gel chemistry and treatment.
Impact of Water Softening on Chemical Enhanced Oil Recovery Project Economics
Authors: Henthorne Lisa , Pope Gary A. , Weerasooriya Upali , Llano Valentina 
Published: June 2014

Abstract
Chemical enhanced oil recovery (EOR) provides the means to increase oil production through manipulation of the chemical and fluid properties within a given reservoir. The number of chemical EOR projects being developed, pilot tested, and commercially implemented is on the rise as a function of the relative decrease in chemical costs, advancements in chemical performance, more precise subsurface modeling, and recent stable oil pricing.
The amount of calcium and magnesium (hardness) in the injection water plays a critical role in determining the type and dosage of alkali, surfactant, co-solvents and/or polymer (ASCP) used in a chemical EOR flood. The hardness dictates whether alkali can be used and affects the surfactant adsorption, achievable viscosity at specific polymer dosages, polymer stability, polymer choice as a function of thermal stability, as well as emulsion stability in the produced water. The ability to remove hardness and thereby use soft injection water with chemical EOR is a game changer, in that it can enable chemical floods that are otherwise uneconomic, infeasible or that are considered too risky. Soft water, invariably, comes at a cost related to treating the source water to remove calcium and magnesium. Source water for a chemical EOR flood is dictated by availability and environmental constraints and is usually limited to produced water, seawater or brine from deep aquifers. Occasionally, a surface water source is available.
This paper reports on representative chemical EOR project case studies in seawater, brackish water and produced water applications at various sites and capacities. The cost of water softening is weighed against the reservoir and production benefits, culminating in a side-by-side economic analysis for each case study based on cost per incremental barrel of oil. The results can be used to guide the development of new chemical EOR projects in determining facility needs as a function of economics.
Challenges in Production Lift Performance Nodal Analysis for Miscible Enhanced Oil Recovery EOR Fields in Deep Water
Authors: Yu Meng , Grego Leonard 
Published: June 2014

Abstract
Deep water oil and gas resources play an important part in the energy mix of today's world, and ultra deep water oil and gas production has been the frontier of the oil and gas industry for the past decades. As the technological advancements push the limits of the industry's capability in the realm of ultra deep water exploration and production, more and more complexities are involved in the technical developments of these fields. Some deep water fields are identified as candidates for enhance oil recovery (EOR) methods. Very recently, several major deep water projects around the globe are including a miscible gas flood in their field development plan. Miscible EOR, combined with extreme conditions such as high temperature, high pressure, ultra deep water and reservoir depths, poses brand new challenges in production engineering designs.
This paper gives a summary of multiple challenges in the production lift performance for green field development of a gas miscible flood in deep water field. The authors have identified several key aspects in the nodal analysis methods that can potentially make significant impact on the accuracy of the predicted production lift performance for such fields. They include, among others, the characterization of fluid PVT (Pressure Volume and Temperature) and its implementation in nodal analysis tools, the use of fit-for-purpose vertical lift correlations, the implementation of compression constraints for gas injection, and the use of subsea pipeline rate multiplier as an approximation for subsea layout. Methodologies of resolving these challenges are proposed, and their limitations are discussed. This paper sheds light on improving the accuracy of nodal analysis of both injection and production for gas miscible EOR fields in deep water.
Performance Review of Gel Polymer Treatments in a Miscible CO2 Enhanced Recovery Project, SACROC Unit Kelly-Snyder Field
Authors: Pipes James W. , Schoeling Lanny G. 
Published: June 2014

Abstract
Conformance issues have plagued the SACROC miscible CO2 flood for many years resulting in poor sweep efficiency and in some cases no sweep with CO2 channeling between wells in major conduits within hours. These conformance problems have led to very high producing GOR's and CO2 gross utilization ratios as well as significant amounts of by-passed pay and unprocessed reservoir volume.
Conformance problems can be addressed in several ways which can be characterized as mechanical (in the wellbore), near wellbore, and/or in-depth treatments in the reservoir. All of these methods have been utilized with varying degrees of success at SACROC. Recently the most long-term success is with large volume gel polymer treatments which plug high permeability channels and conduits and divert injected CO2 to unswept portions of the reservoir.
These treatments generally involve injecting 20,000 barrels or more of polymer gel consisting of Chromium crosslinked medium and high molecular weight polyacrylate polymer. Gel concentrations typically increase from 5000 ppm at the start to as much as 12,000 ppm in the later stages. One of the keys to the success of these treatments is a final, tail-in stage of very high concentration polymer (&gt; 30,000 ppm) or even cement in certain cases to prevent breakdown of the near wellbore gel when the well is returned to injection or production.
These treatments have been implemented in project areas as a result of CO2 early breakthrough and in project areas prior to CO2 injection startup which has resulted in different degrees of success. This paper will discuss 1) candidate selection, 2) treatment design, 3) treatment timing, 4) discussion of results and 5) conclusions with future recommendations. In summary we have concluded that improving CO2 utilization is most effective with large volume treatments. Additionally, maximum benefit is realized when the treatments are implemented prior to CO2 injection in a new set of patterns.
A Novel Procedure To Apply a Relative Permeability Modifier During Perforating Guns and TCP
Authors: Suzart W. , Llerena H. , Lopez E. , Gonzalez M. , Paz F. , Davila E. 
Published: June 2014

Abstract
Water sensitive formations, mature fields, and relatively depleted formations can require complex fluid formulations using specific bottomhole assemblies (BHAs) and underbalanced guns fired to help minimize formation damage. Results have demonstrated that, in many cases where standard procedures were followed, production decreased and such procedures were not always completely effective. This phenomenon can be attributed to formation characteristics, such as kaolinite, smectite, silica incrustations, tertiary precipitations, pH changes, clay swelling, and others.
Relative permeability modifiers (RPMs) are being formulated and used within the oil industry to help mitigate such issues. Physically, the objective is to decrease the relative permeability to water without any (or minimum) modifications of relative permeability to oil. Basically, this methodology can be applied in water wet formations without oil permeability modifications. A standard procedure was executed in four wells and two different formations to prove this technique.
The technique involves using a standard BHA to clean and condition the well, after having selected the zone where the perforating guns will be fired. A specific formulation of RPM treatment is placed inside the casing using a balanced fluid placement technique in front of the section to be shot. This type of fluid has no salinity sensitivity and very low viscosity (less than 4 cp). After placing the RPM fluid, tubing must carefully be pulled out of the hole (POOH) to avoid disturbing and damaging this temporary plug. Guns are run into the hole(RIH) to the selected zone to be perforated after spotting the RPM and then fired, squeezing the system into the desired formations through the casing. The pressure limit must be related to the casing integrity and no more than 1,500 psi as closure pressure (10 min stabilization trend) is measured at surface, and then the final BHA run to begin production.
The primary objective of this paper is to present a non-damaging fluid that can be pumped (or gravity injected) through recently open perforations, reaching casing closure pressure, and changing nearby water permeability, without causing any completion fluid invasion into the formation or induced damage. This process can put the well into production immediately, without any additional cleaning fluid necessary for the removal of the RPM fluid from the formation. The treated wells experienced production with zero damage to formations.
Application of Concepts To Improve Oil Production in Low-Permeability Turbidite Reservoirs in Mexico
Authors: Murillo G. Gutierrez , Rodriguez J. Avendano , Centeno J. Saguero , Medina E. , Perez A. 
Published: June 2014

Abstract
Understanding the complexity of the reservoir is the first step for proper evaluation. By analyzing in an unconventional way using a comprehensive multidisciplinary team analysis and specialized tools to implement innovative completion techniques as the refracturing, multi-stage fracturing, and complex networks of fractures in horizontal wells will an operator have the best opportunity to achieve planned production.
The economic development of low permeability turbidite reservoirs requires efficient application of new techniques and concepts on completion methods and hydraulic fracturing with a precisely planned spacing and well location program to adequately improve the oil production.
However, it is necessary to perform analyses to determine the impact of induced fracture dimensions and orientation in order to maximize the production. The present work is a study performed to analyze some concepts which together could help to improve the production in this type of reservoir. Reservoir average data from a field in Mexico was used to build one simplified and one refined dynamic model. Fractures with different characteristics were built into the models and then simulations were performed and analyzed. This study shows how is the influence of induced fractures dimensions and the impact and benefits of induced fracturing can affect production and overall field development within a secondary recovery program. Additionally, a sensitivity to fracture orientation was simulated to illustrate the impact of knowing hydraulic fracture direction to best develop these tight reservoirs. During this study several scenarios were created and compared with the base case. The Technical and economical evaluation results show that the most profitable scenario is to develop the field with a high density of wells, producing with large induced hydraulic fractures and with water injection pressure support from the beginning of the development.