Jin, Luchao (University of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Jamili, Ahmad (University of Oklahoma) | Li, Zhitao (The University of Texas at Austin) | Luo, Haishan (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Shiau, Ben (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
The surfactant screening process to develop an optimum formulation under reservoir conditions is typically time consuming and expensive. Theories and correlations like HLB, R-ratio and packing parameters have been developed. But none of them can quantitatively consider both the effect of oil type, salinity, hardness and temperature, and model microemulsion phase behavior.
This paper uses the physics based Hydrophilic Lipophilic Difference (HLD) Net Average Curvature (NAC) model, and comprehensively demonstrated its capabilities in predicting the optimum formulation and microemulsion phase behavior based on the ambient conditions and surfactant structures. By using HLD equation and quantitatively characterized parameters, four optimum surfactant formulations are designed for target reservoir with high accuracy compared to experimental results. The microemulsion phase behavior is further predicted, and well matched the measured equilibrium interfacial tension. Its predictability is then reinforced by comparing to the empirical Hand's rule phase behavior model. Surfactant flooding sandpack laboratory tests are also interpreted by UTCHEM chemical flooding simulator coupled with the HLD-NAC phase behavior model.
The results indicate the significance of HLD-NAC equation of state in not only shorten the surfactant screening processes for formulators, but also predicting microemulsion phase behavior based on surfactant structure. A compositional reservoir simulator with such an equation of state will increase its predictability and hence help with the design of surfactant formulation.
Davidson, Andrew (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Unomah, Michael (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan
Low microemulsion viscosity is critical for the success of chemical EOR. Typical microemulsion viscosities are measured using a rheometer and are considered to be static measurements. Given that microemulsions have a propensity to show non-Newtonian behavior, static viscosity measurements are not scalable to dynamic viscosities observed in cores and hence difficult to scale-up to field designs using simulations. We present a technique to measure dynamic microemulsion viscosity using a modified two-phase steady state relative permeability setup. Such dynamic viscosities provide a more practical feel for microemulsion viscosity under reservoir conditions in the pores and allow for selection of low microemulsion viscosity formulations. A two-phase steady state relative permeability setup was used with continuous co-injection of oil and surfactant. A glass filled sand pack was used as a surrogate core and the injection fluids were allowed to equilibrate into the appropriate phases as determined by the phase behavior. For the rapidly equilibrating and low viscosity Winsor Type III formulations three phases are clearly observed in the sand packs. Using the phase cuts in the sand pack/effluent and the known oil and water viscosities, we can estimate the microemulsion viscosity. Both low and high viscosity formulations were tested in corefloods and oil recovery measured to illustrate the importance of low viscosity microemulsions for oil recovery. As expected, the low viscosity microemulsions correlated with higher oil recovery. In addition, the equilibration times to reach Winsor Type III microemulsions were also linked to better oil recovery. For the well behaved formulations that equilibrated in less than 2 days the static microemulsion viscosity correlated well with the dynamic viscosity. The modified steady state relative permeability setup can accurately estimate microemulsion viscosity and allow for better screening of surfactant formulations identified for field flooding. The dynamic microemulsion viscosities can also provide inputs for numerical simulation and better predict microemulsion behavior in the subsurface during field surfactant floods.
Tagavifar, Mohsen (The University of Texas at Austin) | Herath, Sumudu (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin) | Pope, Gary (The University of Texas at Austin)
We made measurements of microemulsion rheology with mixtures of oil, brine, surfactant, co-solvent, and in some cases polymer to systematically investigate the effects of salinity, co-solvents and polymers. A microemulsion rheology model was developed and used to interpret the experimental results. We show that the optimum microemulsion-to-oil viscosity ratio is roughly 5 to 6 without co-solvent, but it can be reduced to a more favorable ratio of ~2 by adding co-solvent. Even though the amount of co-solvent needed is case dependent, a clear trend of microemulsion viscosity reduction with increasing co-solvent concentration was observed. Limited evidence suggests that large hydrolyzed polyacrylamide molecules with a narrow molecular weight distribution have negligible partitioning to type II and III microemulsions.
Skauge, T. (CIPR Uni Research) | Skauge, A. (CIPR Uni Research) | Salmo, I. C. (CIPR Uni Research) | Ormehaug, P. A. (CIPR Uni Research) | Al-Azri, N. (PDO) | Wassing, L. M. (Shell Global Solutions International BV) | Glasbergen, G. (Shell Global Solutions International BV) | Van Wunnik, J. N. (Shell Global Solutions International BV) | Masalmeh, S. K. (Shell Global Solutions International BV)
Polymer injectivity is a critical parameter for implementation of polymer flood projects. An improved understanding of polymer injectivity is important in order to facilitate an increase in polymer EOR implementation. Typically, injectivity studies are performed using linear core floods. Here we demonstrate that polymer flow in radial and linear models may be significantly different and discuss the concept in theoretical and experimental terms.
Linear core floods using partially hydrolyzed polyacrylamides (HPAM) were performed at various rates to determine in-situ viscosity and polymer injectivity. Radial polymer floods were performed on Bentheimer discs (30 cm diameter, 2-3 cm thickness) with pressure taps distributed between a central injector and the perimeter production well. The in-situ rheological data are also compared to bulk rheology. The experimental set up allowed a detailed analysis of pressure changes from well injection to production line in the radial models and using internal pressure taps in linear cores.
Linear core floods show degradation of polymer at high flow rates and a severe degree of shear thickening leading to presumably high injection pressures. This is in agreement with current literature. However, the radial injectivity experiments show a significant reduction in differential pressure compared to the linear core floods. Onset of shear thickening occurs at significantly higher flow velocities than for linear core floods. These data confirm that polymer flow is significantly different in linear and radial flow. This is partly explained by the fact that linear floods are being performed at steady state conditions, while radial injections go through transient (unsteady state) and semi-transient pressure regimes.
History matching of polymer injectivity was performed for radial injection experiments. Differences in polymer injectivity are discussed in the framework of theoretical and experimental considerations. The results may have impact on evaluation of polymer flood projects as polymer injectivity is a key risk factor for implementation.
In this paper, we estimate foam parameters and investigate foam behavior for a given range of water saturation using two local equilibrium foam models: the population balance and the Pc*. Our method uses an optimization algorithm to estimate foam model parameters by matching foam measured pressure gradient from steady-state coreflood experiments. We calculate the effective foam viscosity and the water fractional flow using experimental data and we then compare lab data against results obtained with the matched foam models to verify the foam parameters. Other variables, such as the foam texture and foam relative permeability are used to further investigate the behavior of the foam during each experiment. We propose an improvement to the Pc* model with a better match in high quality regime by assuming resistance factor and critical water saturation is a linear function of pressure gradient. Results show that the parameter estimation method coupled with an optimization algorithm successfully matches the experimental data using both foam models. In the population balance, we observe different values of the foam effective viscosity for each pressure gradient due to variations of the foam texture and shear thinning viscosity effect. The Pc* model presents a constant effective viscosity for each pressure gradient; we propose the use of resistance factor and critical water saturation as a linear function of pressure to improve the match in the high quality regime, when applicable. Foam has been successfully used in the oil industry for conformance and mobility control in gas injection processes. The efficiency of a foam injection project must be assessed by means of numerical models. Although there are several foam flow models in the literature, the prediction of foam behavior is an important issue that needs further investigation.
Microemulsion properties significantly impact any EOR process that relies on surfactants or soaps to generate ultralow interfacial tension to displace trapped oil. Unfavorable microemulsion viscosity can lead to high chemical retention, low oil recovery, and overall unfavorable performance across all modes. Controlling microemulsion properties is important in conventional approaches like surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding, in addition to new applications like gravity stable displacements, spontaneous imbibition in fractured carbonates and unstable floods of viscous oil. Despite the central importance, microemulsion viscosity and rheology remain poorly understood.
This paper describes the results of an extensive experimental microemulsion study. We evaluated the effect of polymer on microemulsion viscosity in different microemulsion phase types (i.e. oil in water, bi-continuous, water in oil emulsions). We measured microemulsion viscosities across a broad salinity range for several crudes from light (API >30°) to heavy oils (API<14°) and observed Newtonian rheology for all phase types. The effect of cosolvents on microemulsion viscosity was also evaluated. Finally, we evaluated microemulsions with and without alkali to help understand potential differences between ASP and SP microemulsions.
We include many observations consistent with earlier literature using recently developed surfactants and report the microemulsion viscosity details for many high performance surfactant formulations across a wide range of conditions. We have also describe several observations, including polymer decreasing the required time to achieve equilibrium in microemulsion pipettes and the qualitative change in microemulsion behavior with and without polymer in Windsor Type III microemulsions.
There is considerable and timely interest in oil and condensate production from liquid-rich regions, placing emphasis on the ability to predict the behavior of gas condensate bank developments and saturation dynamics in shale gas reservoirs. As the pressure in the near-wellbore region drops below the dew-point, liquid droplets are formed and tend to be trapped in small pores. It has been suggested that the injection of CO2 into shale gas reservoirs can be a feasible option to enhance recovery of natural gas and valuable condensate oil, while at the same time sequestering CO2 underground. This work develops simulation capabilities to understand and predict complex transport processes and phase behavior in these reservoirs for efficient and environmentally friendly production management.
Although liquid-rich shale plays are economically producible, existing simulation techniques fail to include many of the production phenomena associated with the fluid system that consists of multiple gas species or phases. In this work, we develop a multicomponent compositional simulator for the modeling of gas-condensate shale reservoirs with complex fracture systems. Related storage and transport mechanisms such as multicomponent apparent permeability (MAP), sorption and molecular diffusion are considered. In order to accurately capture the complicated phase behavior of the multiphase fluids, an equation of State (EOS) based phase package is incorporated into the simulator. Due to the large capillary pressure that exists in the nanopores of ultra-tight shale matrix, the phase package considers the effect of capillary pressure on phase equilibrium calculations. A modified negative-flash algorithm that combines Newton's method and successive substitution iteration (SSI) is used for phase stability analysis under the effect of capillary pressure between oil and gas phases.
In addition, a lower-dimensional discrete fracture and matrix (DFM) model is implemented. The DFM model is based on unstructured gridding, and can accurately and efficiently handle the non-ideal geometries of hydraulic fracture in stimulated unconventional formation. Optimized local grid refinement (LGR) is employed to capture the extremely sharp potential gradient and saturation dynamics in the ultra-tight matrix around fracture.
We apply the developed simulator to study the combined effects of capillary pressure and multicomponent storage and transport mechanisms that are closely associated with the phase behavior and hydrocarbon recovery in gas-condensate shale reservoirs. We present preliminary simulation studies to show the applicability of CO2 huff-n-puff for the purpose of enhanced hydrocarbons recovery. Several design components such as the number of cycles and the length of injection period in the huff-n-puff process are also briefly investigated.
Khorsandi, Saeid (The Pennsylvania State University) | Qiao, Changhe (The Pennsylvania State University) | Johns, Russell T. (The Pennsylvania State University) | Torrealba, Victor A. (The Pennsylvania State University)
Reservoir simulation is a valuable tool for assessing the potential success of enhanced recovery processes. Current chemical flooding reservoir simulators, however, use Hand's model to describe surfactant-oil-brine systems even though Hand's model is not predictive, and can fit only a limited data set. Hand's model requires the tuning of multiple empirical parameters using experimental data that usually consist of salinity scans at constant reservoir temperature and atmospheric pressure. Given experimental data supporting the change in microemulsion phase behavior with key formulation properties (e.g. temperature, pressure, salinity, EACN, and overall composition), there is a need for an improved model that can capture changes in these relevant parameters at the reservoir scale. The recent EOS proposed for microemulsion phase behavior (
In this paper, the EOS model with the extension to two-phase regions is incorporated for the first time into the chemical flooding simulators, UTCHEM, and our new in-house simulator PennSim. Hand's model is only used for comparison purposes, and is no longer needed even for flash calculations in the type II- and type II+ regions. The results show excellent agreement between UTCHEM and PennSim both in composition space and for composition/saturation profiles. Further, the HLD-NAC based EOS model and Hand's models are fitted to the same experimental data and the results of these simulations are nearly identical when variations of salinity, pressure and temperature are small. For large gradients, the results of the physics-based EOS deviates from Hand's model, and shows it is critical to incorporate these gradients in recovery predictions at large scale.
Alexis, Dennis (Chevron Energy Technology Company) | Varadarajan, Dwarakanath (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Winslow, Greg (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company)
Performance of current synthetic EOR polymers is primarily constrained by salinity, temperature and shear which restrict their application to low to moderate salinity, low to moderate temperature and relatively high permeability reservoirs. The primary goal of the current work is to qualify recently developed associative polymers (AP) for EOR applications as well as to study their behavior in porous media. We also compare their performance with conventional non-associative polymers. In this work, we present the evaluation of several associative polymers. Two broad types of associative polymers were tested, one with a partially hydrolyzed poly acrylamide (HPAM) backbone and the other with a sulfonated HPAM backbone. The concentrations of the tested polymer vary between 75 ppm and 1000 ppm. We demonstrate the applicability of these innovative AP's through the carefully controlled lab experiments: (1) Corefloods in sandpacks to compare the sweep behaviors with conventional HPAM's. (2) Single phase flooding experiments are carried out in consolidated outcrop rocks to identify optimal polymer concentrations to achieve the desired in-situ resistance. (3) One dimensional displacement experiments with 8 cP and 90 cP oil are carried out in both unconsolidated and consolidated rocks at different temperatures to validate improved oil recovery. Results generally indicate that associative polymers require lower polymer concentration to generate high resistance factors in porous media and have stable long term injectivity behavior in high permeability rocks (>1D). Associative polymers with HPAM backbone have better filterability and injectivity in comparison to those with HPAM sulfonated backbone in low permeability(<300mD) rocks. Improved oil recovery in high permeability rocks compare well with conventional HPAM and sulfonated HPAM polymers. Based on the laboratory results, we are able to establish the selection baseline for associative polymers in different permeability rocks, salinities and temperatures. Such information can be used to select and screen the appropriate associative polymers, resulting in extending their applicability envelope in EOR.
Compositional reservoir simulation plays a vital role in the development of conventional and unconventional reservoirs. Two major building blocks of compositional simulation are phase behavior and fluid transport computations. The oil and gas reserves and flow of reservoir fluids are strongly dependent on phase behavior. In conventional reservoirs, capillary pressure is relatively small and is typically ignored in phase behavior calculations. However, large capillary pressure values are encountered in tight formations such as shales; and therefore, its effects should not be ignored in phase equilibria calculations. Neglecting the effects of capillary pressure on phase behavior can lead to an inaccurate estimation of original oil and gas in place as well as recovery performance. In spite of this, the effect of capillary pressure on phase behavior in tight reservoirs has not been well studied using compositional simulation, especially for hydraulically-fractured reservoirs.
In this paper, we develop a new compositional reservoir simulator capable of modeling discrete fractures and incorporating the effect of capillary pressure on phase behavior. Large-scale natural and hydraulic fractures in tight rocks and shales are modeled with a technique called Embedded Discrete Fracture Model (EDFM) where fractures are modeled explicitly without using local grid refinement or an unstructured grid. Flow of hydrocarbons occurs simultaneously within similar and different porosity types. Capillary pressure is considered in both flow and flash calculations, where simulations also include variable pore size as a function of gas saturation in each grid block. We examine the impact of capillary pressure on the original oil in place and cumulative oil production for different initial reservoir pressures (above and below the bubble-point pressure) on Bakken and Eagle Ford fluids. The importance of capillary pressure on both flow and flash calculations from hydraulically fractured horizontal wells during primary depletion in fractured tight reservoirs using Bakken fluid composition is demonstrated.
Phase behavior calculations show that bubble-point pressure is suppressed allowing the production to remain in the single-phase region for a longer period of time and altering phase compositions and fluid properties such as density and viscosity of equilibrium liquid and vapor. The results show that bubble-point suppression is larger in the Eagle Ford shale than for Bakken. When capillary pressure is considered, we found an increase in original oil in place up to 4.1% for Bakken and 46.33% for the Eagle Ford crude. Depending on the initial reservoir pressure, cumulative primary production after one year increases owing to capillary pressure by approximately 9.0 – 38.2% for Bakken oil and 7.2 – 154% for Eagle Ford oil. The recovery increase caused by capillary pressure becomes more significant when reservoir pressure is far below bubble-point pressure. The simulation results with hydraulically fractured wells give similar recovery differences; cumulative oil production after 1 year is 3.5 – 5.2% greater when capillary pressure is considered in phase behavior calculations for Bakken.