bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of Small Molecule CO2 Thickeners for EOR and Fracturing
Authors: Lee J. J. , Cummings S. , Dhuwe A. , Enick R. M. , Beckman E. J. , Perry R. , Doherty M. , O'Brien M.
Published: June 2014

The ideal carbon dioxide (CO2) thickener would be an affordable, safe, water-insoluble additive that could dissolve in CO2 at typical wellhead and reservoir conditions during CO2 enhanced oil recovery (EOR) and elevate the viscosity of CO2 to the same value as the oil. Further, the additive would not require heating or an organic co-solvent to achieve dissolution. A CO2 thickener could be a transformative technology in that it would eliminate unfavorable mobility ratios during CO2 EOR and reduce or eliminate the need for WAG. A detailed history of prior attempts to thicken CO2 with either high molecular weight polymers or small associating compounds is presented. Our strategy for designing a novel small molecule CO2 thickener is then detailed. Each thickener candidate contains a strongly CO2-philic segment (e.g. a very short polymer or oligomer of silicone oil or polyprolylene glycol), and one or more somewhat CO2-phobic functional groups that induces intermolecular interactions that can lead to the formation of viscosity-enhancing supramolecular structures in solution.
Combining Conformance Treatment with Mobility Control Increases Enhanced Recovery Factor
Authors: Baker Richard , Lok Crystal , Stephenson Tim , Weghorn Steven
Published: June 2014

Mature water floods with high-permeability sands and medium to heavy-gravity crude oil are prime candidates for enhanced oil recovery (EOR) methods. We examined actual field results from the Buffalo Coulee reservoir. The simulation model was history matched on waterflooding and primary. Forecasts were performed with waterflooding and polymer flooding as well as gel treatments. Results indicated that polymer flooding resulted in a 5 to 8% incremental recovery factor over water flooding, while gel treatments resulted in a 2 to 4% incremental when applied separately. However, when gel treatments were performed immediately prior to polymer flooding, simulation showed the incremental recovery was much higher at 10 to 15%. In other words, there was a large synergistic effect of gels with polymers.

As seen from long-term production data, interwell tracer analysis, pressure pulse tests, and communication analysis, many waterfloods develop preferred water channels due to preferential flow pathways and/or waterflood-induced fracturing. These channels sometimes cycle large volumes of water from injectors to producers in waterfloods with very high water cuts. These channels also can significantly affect the chemical EOR process. Therefore, it is critically important to understand these preferential paths and flow mechanisms in the reservoir and then, in some cases, take corrective action before tertiary EOR is implemented.

Permanently plugging these water channels using crosslinked gel has some significant impacts on improving chemical EOR efficiency and waterflood efficiency. The synergistic effect of the combined treatment significantly improves chemical EOR economics by reducing chemical demand, increasing oil production, decreasing water production, and increasing volumetric sweep.
Injection Water Chemistry Requirement Guidelines for IOR/EOR
Authors: Ayirala S. C. , Yousef A. A.
Published: June 2014

Water chemistry with selective ionic content and composition in the injection water plays a critical role to impact on several oil recovery enhancement processes. Low ionic strength waters with threshold salinities lower than 5,000 ppm are desired for SmartWater flooding in sandstones. Low to moderate salinity waters depleted in monovalents, but enriched in sulfates and divalents are suited for SmartWater flooding in carbonates. Polymer floods mandate different low salinity water lacking both monovalent and divalent ions to reduce polymer dosage and improve project economics. ASP floods require optimal salinity water without the hardness ions to enable utilization of alkali and certain temperature tolerant surfactants in the chemical formulation design. Lower salinity water is desired for carbonated water flooding to increase CO2 dissolved quantities for better incremental oil recovery. Lower salinity waters could turn out to be a boon for even CO2 WAG where low salinity benefits outweigh the adverse CO2 solubility effects. Thermal floods require fresh and hardness free water to generate steam as injectant using boilers.

Injection waters of optimized salinity, ionic content and composition not only work on their own, but can also synergistically combine with other EOR processes to result in higher incremental oil recoveries. Lower salinity waters have a beneficial effect in polymer, surfactant, dilute surfactant and carbonated water floods to yield better oil recoveries when compared to high salinity water. In this paper we first provide an overview on the benefits of tuning injection water salinity and composition in different IOR/EOR processes with selected examples from published data and then propose a unique set of injection water chemistry requirement guidelines for IOR/EOR. The present study findings also point out the need to develop "water chemistry" as a specialty discipline within EOR portfolio and advocate for better integration of this emerging focus area with other key surface and subsurface related disciplines to effectively improve upon IOR/EOR upstream value chain.
Application of Multiple Mixing-Cell Method to Improve Speed and Robustness of Compositional Simulation
Authors: Rezaveisi Mohsen , Johns Russell T. , Sepehrnoori Kamy
Published: June 2014

Standard EOS-based phase equilibrium modeling in reservoir simulators involves computationally intensive and time-consuming iterative calculations for stability analysis and flash calculations. Therefore, speeding up stability analysis and flash calculations and improving robustness of the calculations are of utmost importance in compositional reservoir simulation.

Prior knowledge of the tie lines traversed by the solution of a gas injection problem translates into valuable information with significant implications for speed and robustness of reservoir simulators. The solution of actual gas injection processes follows a very complex route due to dispersion, pressure variations, and multi-dimensional flow. The multiple mixing-cell (MMC) method originally developed to calculate minimum miscibility pressure of a gas injection process, accounts for various levels of mixing of the injected gas and initial oil. This observation suggests that the MMC tie lines developed upon repeated contacts may represent a significant fraction of the actual simulation tie lines encountered. We investigate this idea and use three tie-line-based K-value simulation methods for application of MMC tie lines in reservoir simulation. In two of the tie-line-based K-value simulation methods, we examine tabulation and interpolation of MMC tie lines in a framework similar to the compositional space adaptive tabulation (CSAT). In the third method, we perform K-value simulations based on inverse distance interpolation of K values from MMC tie lines.

We demonstrate that for the displacements examined the MMC tie lines are sufficiently close to the actual simulation tie lines and provide excellent coverage of the simulation compositional route. The MMC-based methods are then compared to the computational time using other methods of phase equilibrium calculations including a modified application of CSAT (an adaptive tie-line-based K-value simulation), a method utilizing only heuristic techniques, and the standard method in an IMPEC-type (implicit pressure, explicit concentration) reservoir simulator. The results show that tabulation and interpolation of MMC tie lines significantly improves phase equilibrium and computational time compared to the standard approach with acceptable accuracy. The results also show that computational performance of the MMC-based methods with only prior tieline tables are very close to that of CSAT, which requires flash calculations during simulation. The K-value simulations using MMC-based tie-line interpolation methods improve the total computational time up to 51% in the cases studied with acceptable accuracy.

The results suggest that MMC tie lines represent a significant fraction of the actual tie lines during simulation and can be used to significantly improve speed and robustness of phase equilibrium calculations in reservoir simulators.
The Effect of Cr(III) Acetate-HPAM Gel Maturity on Washout from Open Fractures
Authors: Brattekås Bergit , Pedersen Stina G. , Nistov Hilde T. , Haugen Åsmund , Graue Arne , Liang Jenn-Tai , Seright Randall S.
Published: June 2014

The blockage performance of a Cr(III) acetate-HPAM gel was investigated using several different application regimes and gel maturities. Fractured core plugs from four outcrop core materials were used, all constituting smooth, longitudinal fractures of 1 mm aperture. Mature and immature gel was placed in the fractures, and for some application regimes in the surrounding core matrix, and the blockage performance assessed by recording rupture pressures and subsequent residual resistance factors during chase waterfloods, Frrw. Placement of mature gel in open fractures yielded consistent rupture pressures during subsequent water injections, following linear trends for given gel placement rates and throughput volumes. The rupture pressures were predictable and stable in all the core materials studied. Rupture pressures achieved after placement and in-situ crosslinking of gelant were comparable to mature gel rupture pressures, but were less predictable. When maximizing gelant saturation in the matrix, rupture pressures were measured to 12 – 53 psi/ft. The maximum achieved rupture pressure when gelant was placed without matrix taps to promote leakoff was 11.9 psi/ft. Interactions between rock material and gelant were observed when Bentheim sandstone cores were used, and gel was in some cases not formed. No such interactions were observed in experiments using formed gel. Significant permeability reduction for water was achieved when both gel and gelant were used. Residual resistance factors for cores treated with gel and gelant were initially comparable. After eight water flushes (>120 fracture volumes (FV) water injected) substantially greater pressure gradients were observed in cores treated with formed gel rather than gelant cross-linked in-situ and the permeability reduction averaged a factor 5000 for gel and 600 for gelant treated cores. The significance of these observations to field applications will be discussed.
A Methodological Analysis of the Mechanisms Associated to Steam-Solvent Co-Injection Processes Using Dynamic Gridding
Authors: Perez-Perez A. , Mujica M. , Bogdanov I. , Hy-Billiot J.
Published: June 2014

Hybrid steam-solvent processes have gained importance as a thermal recovery process for heavy oils in recent years. A number of pilot projects during the last decade indicates the increasing interest in this technology. Steam-solvent co-injection process aims to accelerate oil production, increase ultimate oil recovery, reduce energy and water disposal requirements and diminish the volume of emitted greenhouse gases compared to the steam-assisted gravity drainage (SAGD) process. Among the identified physical mechanisms that play a role during the hybrid steam-solvent processes are the heat transfer phenomena, the gravity drainage and viscous flow, the solvent mass transfer and the mass diffusion/dispersion phenomena. The major consequence of this complex interplay is the improvement of oil phase mobility which is controlled by the reduction in the oil phase viscosity at the edge of the steam chamber. It follows that a detailed representation of this narrow zone is necessary to capture the involved physical phenomena.

In this work, a study of sensitivity to grid size was carried out to define the appropriate grid necessary to represent the near-edge zone of the steam-solvent chamber. Our results for the steam-solvent co-injection process indicate that a decimetric scale is required to represent with a good precision the heat and mass transfer processes taking place at the edge of the steam chamber. In addition, we present some numerical results of the adaptive dynamic gridding application. Comparison was done between the SAGD process and steam-solvent co-injection after the characterization and analysis of the mechanisms which govern the oil production under the typical Athabasca oil sand conditions. Finally, in the framework of the proposed numerical methodology the effect of solvent type and injection conditions on the oil recovery efficiency is quantitatively illustrated. Published data for similar applications are also discussed.

It is expected that this work will provide some insight to the simulation community about methodological aspects to be taken into account when hybrid steam-solvent processes would be modeled.
Correlation of Pure Water Saturation Properties by Equations of State Using the Association Concept
Authors: Forouzanfar F. , Pires A. P. , Reynolds A. C.
Published: June 2014

Modeling of enhanced / improved oil recovery processes that takes into account mass transfer between phases depends on the correct prediction of thermodynamic properties and composition of phases in equilibrium. In a steam flood process, the mutual water / hydrocarbons solubility is a function of the temperature, pressure and fluid composition of the system and may not be negligible at flooding conditions. The most used equations of state (EoS) in the petroleum industry fail to accurately correlate saturation properties of polar substances that self-associate through hydrogen bonding and as a consequence, do not calculate the distribution of the components among equilibrium phases precisely. In this paper, we present the development of the Association Peng-Robinson and Association Soave-Redlich-Kwong equations of state. The proposed equations of state are composed of two parts, one physical (the original cubic equation of state model) and one chemical (an empirical chemical reaction term which accounts for the self-association of a component) and can be used to model systems in equilibrium that contain one associating component such as water or alcohol. In the extended equations of state which includes the self-association chemical reaction, the degree of the molar volume polynomial is increased from its normal value of three to six but, in general, there are only three positive roots. The chemical part of the extended EoS includes three parameters that can be adjusted to match data, the entropy and enthalpy of the association chemical reaction and one free parameter. The fugacity calculations for the extended EoS can be split into physical and chemical parts, where the physical part has exactly the same form as the original equation of state fugacities. In order to estimate the new parameters of the proposed equations of state, the differences between the experimental and calculated saturation pressure and saturated liquid molar volume of pure water are minimized using a Particle Swarm Optimization (PSO) algorithm. The equations of state presented here enhance the original ones through the addition of a chemical part to deal with self-associating polar components. The average relative deviation between the experimental and calculated saturated data using the association forms of the Peng-Robinson and Soave-Redlich-Kwong equations of state are smaller than those obtained from the original models. The chemical reaction approach is robust and improves the prediction of thermodynamic equilibrium properties of self-associating pure components by adding only three adjustable parameters, where two of them have a clear physical meaning (self-associating reaction enthalpy and entropy).
Three-Phase Relative Permeabilities as a Function of Flow History
Authors: Kianinejad A. , Aminzadeh B. , Chen X. , DiCarlo D. A.
Published: June 2014

Three-phase relative permeability is one of the main parameters in flow predictions of tertiary recovery processes in petroleum reservoirs. In particular, an understanding of the hysteresis in three phase relative permeability is essential to describe cyclic processes such as water alternating gas (WAG) injection. Several studies measured three-phase relative permeabilities through steady-state and unsteady-state indirect methods, with their own advantage and disadvantages. Among these, unsteady-state direct measurements are preferred since they mimic the natural reservoir processes while no assumptions are made for relative permeability calculations. But, previous unsteady-state direct measurements of three-phase relative permeability obtained relative permeabilities only during drainage processes. In this work, we extend this method to directly obtain oil and water relative permeabilities during three-phase flow through different flow cycles. The method involves in-situ measurements of phase saturation, and a combination of applied gas and water flow to overcome the limitations of previous direct relative permeability measurements. This method is used to directly measure the three-phase hysteresis effects in relative permeability. Specifically, we perform flow experiments in a 3ft long, vertically oriented sand pack; the sand pack is initialized at a specific oil saturation using two-phase flow. As opposed to previous unsteady-state direct measurements of three-phase permeabilities, gas and water are injected separately as different cycles and, the saturation along the sand pack is measured at different times using computerized tomography scanning. The relative permeability of each phase is then obtained directly from the measured in-situ saturations using Darcy's law. The results show that, we should pick only the middle 40cm of the saturation data to avoid the effect of capillary entry and capillary end effects on saturation data. Experimentally, we find that, the oil relative permeability rises at the beginning of each WAG cycle and then decreases almost as abruptly, with very little dependence on the phase saturations. On the other hand, the water relative permeability remains almost constant. The results also show that, the residual oil saturation decreases during the WAG process at different cycles. The results are discussed in terms of local flow processes, and potential implications for reservoir flooding are given.
Low Salinity Water Flooding: Effect Of Crude Oil Composition
Authors: Fjelde Ingebret , Omekeh Aruoture Voke , Sokama-Neuyam Yen Adams
Published: June 2014

Reduction of the salinity of injection water has been found to improve the oil recovery in some sandstone reservoir rocks, but for other sandstone rocks disappointing results have been obtained. No mechanism has been widely accepted as the reason for the improved oil recovery in low salinity water flooding (LSWF). Since alteration of wettability to more water-wet conditions has been reported in promising cases, desorption of crude oil components from the minerals surfaces should occur during LSWF. Retention of oil components onto sandstone reservoir rock saturated with brines of different compositions has been studied by injecting crude oils of different compositions. Results from experiments and simulation of rock-brine interactions have been compared.

In the study it has been shown that the compositions of both low salinity water and the crude oil are important for the retention of polar oil components. For the original crude oil with the lowest base/acid ratio, the retention of oil components was found to vary with the brine composition even though the total salinity was the same. For this crude oil the measured decrease in the retention of oil components was found to be in accordance with simulated decrease in the total concentration of divalent cations on clay surfaces. This indicated that the retention of oil components were dominated by bonding of carboxylic groups to clay surfaces by cation-bridging. For treated crude oil with reduced amount of acidic components (highest base/acid ratio), the retention of polar oil components was not sensitive to the brine salinity/composition and was higher than for the original oil (with lowest base/acid ratio). The retention was for this oil probably due to direct adsorption of basic components. The retention was therefore found to be sensitive to the concentration of acids in the crude oil, and was increasing with increasing base/acid ratio.

It has been shown the ionic composition of the low salinity brine and the composition of the crude oil are important for the retention of polar oil components and thereby the wettability. The optimum low salinity water composition will depend on the formation water composition, mineral composition/distribution of reservoir rock and oil composition, and for tertiary LSWF also the composition of earlier injection brine.
A Mechanistic Integrated Geochemical and Chemical Flooding Tool for Alkaline/Surfactant/Polymer Floods
Authors: Korrani Aboulghasem Kazemi , Sepehrnoori Kamy , Delshad Mojdeh
Published: June 2014

Mechanistic simulation of alkaline/surfactant/polymer (ASP) flooding considers chemical reactions between the alkali and the oil to form in-situ soap and reactions between the alkali and the minerals and brine. A comprehensive mechanistic modeling of such process remains a challenge, mainly due to the complicated ASP phase behavior and the complexity of geochemical reactions that occur in the reservoir. Due to the lack of the microemulsion phase and/or lack of reactions that may lead to the consumption of alkali and resulting lag in the pH, a simplified ASP phase behavior is often used.

UTCHEM-IPhreeqc, a previously developed robust, accurate, and flexible integrated tool at the University of Texas at Austin (UT), is further expanded to mechanistically model ASP floods. UTCHEM has a comprehensive three-phase (water, oil, microemulsion) phase behavior model for the mixture of surfactant and soap as a function of salinity, temperature, and co-solvent concentration. IPhreeqc, a state-of-the-art geochemical package of the United States Geological Survey (USGS), handles the geochemical reactions involved between crude oil, rock, and brine.

Through this integrated tool, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, surface complexation, and ion-exchange reactions under non-isothermal, non-isobaric, and both local-equilibrium and kinetic conditions. IPhreeqc has rich databases of chemical species and also the flexibility to define the alkali reactions required for the ASP modeling. Hence, to the best of our knowledge, for the first time, the important aspects of ASP flooding are considered.

The expanded integrated tool, UTCHEM-IPhreeqc, is then used to match three different reaction-related chemical flooding processes: ASP flooding in an acidic active crude oil, ASP flooding in a non-acidic crude oil, and alkaline/co-solvent/polymer (ACP) flooding.
Is Wettability Alteration the Main Cause for Enhanced Recovery in Low-Salinity Waterflooding?
Authors: Kasmaei A. Kafili , Rao D. N.
Published: June 2014

Low salinity waterflooding is gaining some attention in the recent literature as a means of improving oil recoveries. However, a clear understanding of the key mechanism(s) of low-salinity waterflooding does not seem to have emerged although wettability alteration is repeatedly cited as the cause for the observed effects, albeit without much experimental evidence. Moreover, much of the reported low-salinity work appears to be related to sandstone reservoirs.

In this study, we have attempted to investigate the role wettability alteration plays in low-salinity waterflooding by conducting dual-drop-dual-crystal contact angle measurements to characterize wettability changes and coreflood experiments for oil recovery and oil/water relative permeability measurements using a dolomite reservoir rock-fluids system. Additional experiments have been conducted to examine the roles of brine chemistry and the temperature in altering wettability in low-salinity waterfloods.

The contact angle results clearly indicate the wettability alteration from an oil-wet state (with a water-advancing contact angle of 158°) to an intermediate state (with an advancing contact angle of 113°) caused by diluting the reservoir brine to one-fiftieth of its original strength. A similar result was obtained when the sulfate concentration in the reservoir brine was doubled and when the temperature was increased to 250°F from the reservoir temperature of 80°F. These wettability alterations as measured by contact angles were confirmed by coreflood experiments that yielded significantly higher recoveries (from about 46% to about 76%) due to low-salinity flooding, alteration of brine composition and temperature.

This experimental study confirms the major influence of wettability in low-salinity waterflooding of a dolomite reservoir.
Analyzing the Reservoir Performance of an Expanding Solvent - Steam Assisted Gravity Drainage (ES-SAGD) Process Using a Semi-Analytical Approach
Authors: Kannan K. , Srinivasan S.
Published: June 2014

Steam Assisted Gravity Drainage (SAGD), through many successful field projects, has proven to be an effective process for improved recovery of heavy oil and bitumen from subsurface reservoirs. However, the continued search for a more energy efficient method has led to the development of an improved process called Expanding Solvent (ES)-SAGD that has the potential to accelerate recovery with less steam requirement per barrel of oil produced. Understanding the physics associated with this process is key for making robust predictions regarding the process performance. In this paper, a semi-analytical model is discussed, which can be used to determine the performance of the ES-SAGD process. The results of the semi-analytical model are compared to 2D numerical simulation results in order to validate the model.

The semi-analytical model, an extension to the model by Gupta et al. (2012) is developed by combining Butler's (Butler et al., 1981, 1985) oil drainage analytical expression for SAGD and VAPEX (Gupta el., 2010) solvent dilution effects. This approach, with some modifications, is validated by the use of a 2D simulation. Numerical simulation of a short length-scale process like solvent dilution in oil sometimes may yield less accurate result prediction due to inherent numerical dispersion issues. Dynamic gridding based on both temperature and concentration change criterion is demonstrated to be one of the viable options to obviate this issue.

Trends for bitumen production rate and some key operation parameters obtained using the semi-analytical model are in good agreement with the numerical simulation results, rendering this model suitable for performing solvents-screening studies. However, there are some differences in magnitude of the results between the simulation and semi-analytical method that can be attributed to grid orientation effects. Modifications to the semi-anlayitcal approach and reservoir model used in 2D simulations have been made to minimize the observed differences.

It can be concluded that the approach discussed in this paper could give a preliminary estimate of the key parameters that affect the recovery using the ES-SAGD process. The paper also presents some useful guidelines for simulating the process performance using current commercial simulators.
Synergistic Stabilization of Foams by a Mixture of Nanoparticles and Surfactants
Authors: Singh Robin , Mohanty Kishore K.
Published: June 2014

The goal of this work is to evaluate stabilization of foams by a combination of nanoparticles and surfactants. Hydrophilic silica nanoparticles (NP) and anionic surfactants were used in this study. Static foams were generated using surfactants and surfactant-NP mixtures with and without the presence of a crude oil. The decay of the foam height with time was studied and half-lives were determined. The foam drainage behavior and thickness of the foam lamella were studied by fluorescence microscopy. Aqueous foams were created in-situ by co-injecting the surfactant or surfactant-NP mixtures with nitrogen gas through a Berea sandstone core at a fixed quality. Pressure drop across the core was measured to estimate the achieved mobility reduction factor (MRF). Oil displacement experiments were conducted in Berea cores using surfactant and surfactant-nanoparticle mixture as foaming agents. Static foam tests indicate stabilization effect of nanoparticles on surfactant-nanoparticle foam stability in the absence of crude oil. Lighter crude oils were more destabilizing to foams than heavier oils. Adding nanoparticles even in low concentrations (0.3 wt %) can significantly improve the foam stability and mobility reduction factor in the absence of oil. As the concentration of nanoparticles increased, mobility reduction factor (MRF) of surfactant-nanoparticle foam in a Berea core increased significantly. Fluorescence microscopy elucidated that nanoparticles are trapped in the plateau border as well as lamellas which retard liquid drainage and bubble coalescence. The core floods with a crude oil revealed that the incremental oil recovery by surfactant-NP blend over water flood was about 10% OOIP with an immiscible foam.
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

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

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

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

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

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

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

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

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 (> 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.