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Collaborating Authors
Chemical flooding methods
Summary This article reports a laboratory study of a novel alkaline/surfactant/foam (ASF) process. The goal of the study was to investigate whether foaming a specially designed alkaline/surfactant (AS) formulation could meet the two key requirements for a good enhanced oil recovery (EOR) [i.e., lowering the interfacial tension (IFT) considerably and ensuring a good mobility control]. The study included phase-behavior tests, foam-column tests, and computed-tomography (CT)-scan-aided corefloods. It was found that the IFT of the designed AS and a selected crude oil drops by four orders of magnitude at the optimum salinity. The AS proved to be a good foaming agent in the column tests and corefloods in the absence of oil. The mobility reduction caused by the AS foam was hardly sensitive to salinity and increased with decreasing foam quality. CT-scanned corefloods demonstrated that AS foam, after a small AS preflush, recovered almost all the oil left after waterflooding. The oil-recovery mechanism by ASF combines the formation of an oil bank and the transport of emulsified oil by flowing lamellae. Further optimization of the ASF is needed to ensure that the oil is produced exclusively by the oil bank.
- North America > United States > Louisiana (0.28)
- North America > United States > Oklahoma (0.28)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Alkali Surfactant Gas Injection: Attractive Laboratory Results Under the Harsh Salinity and Temperature Conditions of Middle East Carbonates
Cottin, C.. (TOTAL E&P Pau FRANCE) | Morel, D.. (TOTAL E&P Pau FRANCE) | Levitt, D.. (TOTAL E&P Pau FRANCE) | Cordelier, P.. (TOTAL E&P Pau FRANCE) | Pope, G.. (The University of Texas at Austin, USA)
Abstract Alkali-surfactant-polymer (ASP) injection is an attractive enhanced oil recovery (EOR) technique that allows achieving almost zero residual oil saturation at the microscopic scale when well designed. In this combination of chemicals, the role of polymer is to achieve the necessary mobility control of the microemulsion / oil fronts which are formed and propagated through the reservoir. Foam has been recently identified as an alternative to polymer to achieve such mobility control. This paper describes the alkali-surfactant-gas (ASG) and surfactant-gas (SG) laboratory results which have been obtained on carbonate core samples under harsh salinity (~230 g/L) and temperature (83°C) conditions representative of some Middle East reservoirs. The starting point was the development of a surfactant formulation to achieve ultra-low interfacial tension between the oil and injected solution in these particular salinity and temperature conditions, using the classical microemulsion phase behavior approach. This formulation used a class of surfactants newly developed at The University of Texas at Austin (UTA), compatible with and without divalent ions. The efficiency (in terms of oil recovery) of this chemical formulation was demonstrated with SP core floods. The same chemical formulation was used for SG as the starting point, and was further enhanced; the polymer was replaced by nitrogen or methane co-injected with surfactant to create foam. Extensive studies of the ASG process have been performed. This includes phase behavior with and without alkali, screening laboratory studies to pre-select the surfactant with adequate foam properties, and carbonate coreflood experiments to measure the residual oil saturation to SG injection, including the consumption of chemicals. There is still room for optimization, but very promising results have already been obtained on that particular case leading to high recovery of the remaining oil after waterflood.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Foam-assisted underbalanced drilling technique is advantageous over the traditional overbalanced drilling near the productive water-sensitive formations due to its reduced formation damage, improved rate of penetration, higher cutting-transport capacity, and lower circulation losses. However, the complicated nature of foam rheology has been a major impediment to the optimal design of field applications. Earlier studies with surfactant foams without oils and polymers show that foam flow in pipe can be represented by two different flow regimes: the low-quality regime showing either plug-flow or segregated-flow pattern, and the high-quality regime showing slug-flow pattern. The objective of this study is to investigate foam flow characteristics in horizontal pipes at different injection conditions, with or without oils, by using polymer-free and polymer-added surfactant foams. The results of this study were presented in two different ways: (i) steady-state pressure drops (or, apparent foam viscosity, equivalently) measured by multiple pressure taps and (ii) visualization of bubble size, size distribution and flow patterns in transparent pipes. The results with surfactant foams and oil showed that (i) oil reduced the stability of foams in pipes, hence, decreasing the steady-state pressure drops and foam viscosities, and (ii) the presence of oil tended to lower the transition between the high-quality and the low-quality regimes (i.e., lower foam quality at the boundary, or lower fg* equivalently). In addition, the results with surfactant foams with polymer showed that (i) polymer thickened the liquid phase and, if enough agitation was supplied, could make foams long-lived and improve foam viscosities, and (ii) the system sometimes did not reach the steady state readily, showing systematic oscillations. In both cases, though, the experiments carried out in this study showed the presence of two distinct high-quality and low-quality flow regimes.
- Europe (0.68)
- North America > United States > California (0.46)
- North America > Canada > Alberta (0.28)
- Well Drilling > Pressure Management > Underbalanced drilling (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Study of the Effect of Different Factors on Nanoparticle-Stablized CO2 Foam for Mobility Control
Mo, Di (Petroleum Recovery and Research Center, New Mexico Institute of Mining and Technology, Socorro, NM 87801) | Yu, Jianjia (Petroleum Recovery and Research Center, New Mexico Institute of Mining and Technology, Socorro, NM 87801) | Liu, Ning (Petroleum Recovery and Research Center, New Mexico Institute of Mining and Technology, Socorro, NM 87801) | Lee, Robert (Petroleum Recovery and Research Center, New Mexico Institute of Mining and Technology, Socorro, NM 87801)
Abstract This paper describes a s eries of nanoparticle-stabilized CO2-foam flow experiments performed at reservoir conditions of 20°C and 1200 psig. The generation of CO2 foam was observed in an online sapphire tube. Pressure drop across the core was measured to estimate the fluid mobility and foam resistance factor. Results from the experiments show that stable CO2 foam was generated when CO2 and nanosilica dispersion flowed through a core sample. CO2 foam can be generated with the nanosilica concentration as low as 100 ppm. With the increase of nanosilica concentration, foam mobility decreased and the foam resistance factor increased. It was also observed that the foam mobility decreased with increasing foam quality from 20% to 60% and then increased as the foam quality increased from 60% to 80%. The effects of flow rate on foam mobility indicated that CO2 foam mobility decreased with the flow rate increasing from 60ml/h to 160ml/h.
- North America > United States > Texas (0.46)
- North America > United States > New Mexico (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract Foam as a gas-mobility control agent is successful in enhanced oil recovery processes. An emerging application of foam is to aid surfactant solution delivery for EOR in heterogeneous porous media. In fractured reservoirs, foam acts as a blocking agent slowing and redirecting the transport of the aqueous phase in high transmissibility fractures. Foam aids the imbibition of foamer/surfactant solution into the matrix blocks so that remaining oil is drained. The design of such foam treatments for fractured media is an important factor for economic as well as recovery success. In this work we investigate the behavior of foam flow in fractures at various foam qualities and liquid and gas velocities. Laboratory experiments with different fracture replicates etched in silicon micromodels were used. Micromodels allow real time observations of flow behavior with a microscope and provide a fracture geometry that is easily replicated. A plain smooth fracture with different apertures (40 μm and 30 μm), a fracture with variable smooth apertures (either 20 μm or 40 μm) arranged in a checkerboard pattern and a constant-aperture fracture with a rough face were used to observe pre-generated foam in terms of texture, pressure drop and flow behavior. Mobility reduction factors for a wide range of foam qualities and flow rates were analyzed. Measured pressure drops increase linearly with an increase in foam quality up to 90%. At qualities greater than 90%, mobility reduction is only slightly reduced further. In general, mobility reduction factors (MRF) of 10-600 times were measured for low to high quality foams, respectively. Additionally video footage of foam at micro and macro scale is used to tie rheology to bubble shape and size. Study results are useful as input for upscaling of the rheology of foam fractures and for ultimate use in reservoir simulations to design effective chemical EOR treatments for fractured media.
- North America > United States > Oklahoma (0.46)
- North America > United States > Texas (0.46)
- North America > United States > California (0.46)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.93)
Understanding Foam Flow with a New Foam EOR Model Developed from Laboratory and Field Data of the Naturally Fractured Cantarell Field
Skoreyko, Fraser (Computer Modelling Group) | Villavicencio, Antonio Pino (Pemex E&P) | Prada, Hector Rodríguez (Independent Consultant for Pemex) | Nguyen, Quoc P. (University of Texas at Austin)
Abstract As much of the oil in the Akal field of the Cantarell complex is contained in the low permeability oil wet matrix, foam injection has been proposed as a method to control fluid mobility in the fracture, with the possible added benefit of transporting surfactant into the matrix so that additional oil could be liberated through a reduction of interfacial tension between oil and water (if this effect is significant for the surfactant in question). Presented in this paper is the work flow undertaken during an extensive study of all available laboratory experiments and pilot single well foam injection tests. Laboratory experiments ranged from simple water plus surfactant imbibition tests and surfactant flooding tests, to more complex foam flooding in split core experiments and co-injection of surfactant and gas for generation of foam in-situ. There were three field pilot single well foam injection tests that were included in this analysis that were of the huff-and-puff design. This extensive analysis was done with the aid of numerical simulation that resulted in the development of a novel foam model that handles both mobility control and interfacial tension reduction effects, and is capable of simulating foam degradation, foam regeneration, and trapped foam phenomena. Previous foam models available in commercial numerical simulators were not capable of simulating all of these foam effects together. It is shown that with identical foam parameters, this model matches all laboratory core flood studies as well as the field pilot tests, showing that this foam model is capable of predicting foam performance in both laboratory and field settings. The foam components can be chosen to be defined as either gaseous or aqueous components and this choice is shown to affect the impact of capillary pressure on foam flow into the matrix. Also discussed in this paper are details of how the foam behaves when injected into a gas saturated zone where the foam combines with in-situ gas, resulting in higher foam qualities than was injected. It is demonstrated that foam mobility control as a function of foam quality is an important aspect for matching field performance. The significance of correct foam density calculations is also discussed using field scale models. The work done to match the many laboratory and field scale foam tests resulted in a significant improvement of the understanding of foam degradation, regeneration, permeability blockage, and flow in porous media and the phenomena responsible for generating incremental oil.
- North America > United States (1.00)
- North America > Mexico > Gulf of Mexico > Bay of Campeche (1.00)
- Europe (1.00)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Northeast Marine Region > Cantarell Field (0.99)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Northeast Marine Region > Akal Field (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- (12 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)