Compositional Effects on Displacement Mechanisms of the Micellar Fluid Injected in the Sloss Field Test

1984 ◽  
Vol 24 (01) ◽  
pp. 38-48 ◽  
Author(s):  
Surendra P. Gupta
Keyword(s):  
Ion Exchange ◽  
Oil Recovery ◽  
Mobility Control ◽  
Laboratory Studies ◽  
Pilot Performance ◽  
Time Effects ◽  
Oil Saturation ◽  
Compositional Effects ◽  
Mechanistic Understanding ◽  
Composition Changes

Abstract The performance of the micellar/polymer flood conducted in the Sloss reservoir did not follow predictions by a streamtube model. The model assumed that micellar flood displaces oil and water in a piston-type miscible manner with a final oil saturation of 5 % PV, and sulfonate retention based on short-term laboratory adsorption tests. This paper, in conjunction with a complementary paper,1 describes process mechanisms needed to model the flood performance. The results of laboratory studies show higher sulfonate retention caused by ion-exchange effects, which result in partitioning of sulfonate into the oil phase and higher adsorption caused by long contact times. Long-term aging of the Sloss micellar fluid at the high reservoir temperature (93.3°C [200°F]) does not reduce oil recovery. The results of laboratory studies also show that the final oil saturation after micellar flooding is capillary-number dependent. A higher final oil saturation can be the result of reduced injectivity /productivity, increased interfacial tension (1FT), and/or decreased viscosity. This paper demonstrates that ion exchange, hardness, and sulfonate partitioning can significantly affect micellar-flood performance. The paper presents an experimental plan that provides information for optimizing the design of micellar/polymer floods. This plan, when applied to a specific flood, allows an investigator to examine effects of adsorption, ion exchange, hardness, and partitioning on flood performance. Specifically, phase studies and sulfonate requirements must encompass effects of in-situ-generated calcium ions as a result of sodium/calcium ion exchange. Sulfonate itself can increase the calcium content of the fluids because of a calcium/micelle association. High calcium concentrations can increase sulfonate requirements. Sulfonate adsorption requirements for micellar flood design are sensitive to the experimental procedures employed. The paper outlines improved procedures encompassing ion exchange and time effects and demonstrates that a favorable ion-exchange process can be used to reduce adsorption requirements. Introduction Interpretation of micellar-flooding pilots is essential to the development of a predictive model for commercial demonstration and fieldwide micellar floods. To interpret field micellar-flood performance, process variables (e.g., compositional effects) must be separated from field variables (e.g., reservoir description and operational difficulties), and the process mechanisms must be identified. This paper describes experimental procedures for use by industry to identify effects of composition changes during micellar flooding. The paper describes application of these procedures to determine the effects of composition changes on the displacement mechanisms of the micellar/polymer fluids injected in the Sloss field, Kimball County, NE.2 The results enhanced our mechanistic understanding of the micellar-flooding process. This understanding is required for interpretation of pilot performance. This paper discusses the first portion of the mechanism studies for the micellar/polymer system used in the Sloss reservoir. Results of the second portion of the mechanism research were published in 1982.1 A separate paper discussed results of the Sloss pilot posttest evaluation well.3 Pilot Performance The streamtube model with classical miscible-immiscible displacements was used to obtain preflood predictions.1 This model assumed sulfonate retention (by adsorption) of 3.42 kg active Mahogany AA sulfonate/m3 contacted PV [1.20 lbm/bbl PV], a final oil saturation of 5 % PV in the micellar swept zone, and mobility control. The preflood predictions and pilot performance were in excellent agreement during the early stages of the project.2 However, the observed performance later deviated from the preflood predicted performance.2,4 Postflood predictions by the same model more closely matched total pilot performance by assuming an increased sulfonate retention and a higher final oil saturation. Process Mechanism Studies Detailed laboratory studies were initiated to enhance our mechanistic understanding of the process. These studies needed for interpretation of the pilot performance included:phase behavior,compositional effects on oil displacement,propagation of the oil and micellar banks,ion-exchange behavior,sulfonate retention,time effects on sulfonate adsorption, andeffect of micellar fluid aging on oil recovery.

scholarly journals MICROEMULSION FLOODING MECHANISM FOR OPTIMUM OIL RECOVERY ON CHEMICAL INJECTION

2018 ◽  
Vol 40 (2) ◽  
pp. 85-90
Author(s):  
Yani Faozani Alli ◽  
Edward ML Tobing ◽  
Usman Usman
Keyword(s):  
Oil Recovery ◽  
Mobility Control ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Core Flooding ◽  
Oil Viscosity ◽  
Oil Saturation ◽  
Remaining Oil ◽  
Tertiary Oil Recovery

The formation of microemulsion in the injection of surfactant at chemical flooding is crucial for the effectiveness of injection. Microemulsion can be obtained either by mixing the surfactant and oil at the surface or injecting surfactant into the reservoir to form in situ microemulsion. Its translucent homogeneous mixtures of oil and water in the presence of surfactant is believed to displace the remaining oil in the reservoir. Previously, we showed the effect of microemulsion-based surfactant formulation to reduce the interfacial tension (IFT) of oil and water to the ultralow level that suffi cient enough to overcome the capillary pressure in the pore throat and mobilize the residual oil. However, the effectiveness of microemulsion flooding to enhance the oil recovery in the targeted representative core has not been investigated.In this article, the performance of microemulsion-based surfactant formulation to improve the oil recovery in the reservoir condition was investigated in the laboratory scale through the core flooding experiment. Microemulsion-based formulation consist of 2% surfactant A and 0.85% of alkaline sodium carbonate (Na2CO3) were prepared by mixing with synthetic soften brine (SSB) in the presence of various concentration of polymer for improving the mobility control. The viscosity of surfactant-polymer in the presence of alkaline (ASP) and polymer drive that used for chemical injection slug were measured. The tertiary oil recovery experiment was carried out using core flooding apparatus to study the ability of microemulsion-based formulation to recover the oil production. The results showed that polymer at 2200 ppm in the ASP mixtures can generate 12.16 cP solution which is twice higher than the oil viscosity to prevent the fi ngering occurrence. Whereas single polymer drive at 1300 ppm was able to produce 15.15 cP polymer solution due to the absence of alkaline. Core flooding experiment result with design injection of 0.15 PV ASP followed by 1.5 PV polymer showed that the additional oil recovery after waterflood can be obtained as high as 93.41% of remaining oil saturation after waterflood (Sor), or 57.71% of initial oil saturation (Soi). Those results conclude that the microemulsion-based surfactant flooding is the most effective mechanism to achieve the optimum oil recovery in the targeted reservoir.

Surfactant Prefloods During Carbon Dioxide Foam Injection for Integrated Enhanced Oil Recovery in Fractured Oil-Wet Carbonates

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1139-1153 ◽  
Author(s):  
S. B. Fredriksen ◽  
Z. P. Alcorn ◽  
A.. Frøland ◽  
A.. Viken ◽  
A. U. Rognmo ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Surfactant Solution ◽  
Mobility Control ◽  
Threshold Pressure ◽  
Oil Saturation ◽  
Co2 Foam ◽  
Matrix Blocks ◽  
Carbon Dioxide Co2

Summary An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.

The Method of Characteristics Applied to Oil Displacement by Foam

SPE Journal ◽  
2010 ◽  
Vol 16 (01) ◽  
pp. 8-23 ◽  
Author(s):  
M.. Namdar Zanganeh ◽  
S.I.. I. Kam ◽  
T.C.. C. LaForce ◽  
W.R.. R. Rossen
Keyword(s):  
Capillary Pressure ◽  
Oil Recovery ◽  
Method Of Characteristics ◽  
Water Saturation ◽  
Gas Injection ◽  
Mobility Control ◽  
Residual Water ◽  
Injection Point ◽  
Oil Saturation ◽  
The Method Of Characteristics

Summary Solutions obtained by the method of characteristics (MOC) provide key insights into complex foam enhanced-oil-recovery (EOR) displacements and the simulators that represent them. Most applications of the MOC to foam have excluded oil. We extend the MOC to foam flow with oil, where foam is weakened or destroyed by oil saturations above a critical oil saturation and/or weakened or destroyed at low water saturations, as seen in experiments and represented in foam simulators. Simulators account for the effects of oil and capillary pressure on foam using algorithms that bring foam strength to zero as a function of oil or water saturation, respectively. Different simulators use different algorithms to accomplish this. We examine SAG (surfactant-alternating-gas) and continuous foam-flood (coinjection of gas and surfactant solution) processes in one dimension, using both the MOC and numerical simulation. We find that the way simulators express the negative effect of oil or water saturation on foam can have a large effect on the calculated nature of the displacement. For instance, for gas injection in a SAG process, if foam collapses at the injection point because of infinite capillary pressure, foam has almost no effect on the displacement in the cases examined here. On the other hand, if foam maintains finite strength at the injection point in the gas-injection cycle of a SAG process, displacement leads to implied success in several cases. However, successful mobility control is always possible with continuous foam flood if the initial oil saturation in the reservoir is below the critical oil saturation above which foam collapses. The resulting displacements can be complex. One may observe, for instance, foam propagation predicted at residual water saturation, with zero flow of water. In other cases, the displacement jumps in a shock past the entire range of conditions in which foam forms. We examine the sensitivity of the displacement to initial oil and water saturations in the reservoir, the foam quality, the functional forms used to express foam sensitivity to oil and water saturations, and linear and nonlinear relative permeability models.

scholarly journals Experimental investigation of the displacement flow mechanism and oil recovery in primary polymer flood operations

2021 ◽  
Vol 3 (5) ◽  
Author(s):  
Ruissein Mahon ◽  
Gbenga Oluyemi ◽  
Babs Oyeneyin ◽  
Yakubu Balogun
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Mobility Control ◽  
List Type ◽  
Motor Oil ◽  
Flow Mechanism ◽  
Fractional Flow ◽  
Recovery Method ◽  
Polymer Flood

Abstract Polymer flooding is a mature chemical enhanced oil recovery method employed in oilfields at pilot testing and field scales. Although results from these applications empirically demonstrate the higher displacement efficiency of polymer flooding over waterflooding operations, the fact remains that not all the oil will be recovered. Thus, continued research attention is needed to further understand the displacement flow mechanism of the immiscible process and the rock–fluid interaction propagated by the multiphase flow during polymer flooding operations. In this study, displacement sequence experiments were conducted to investigate the viscosifying effect of polymer solutions on oil recovery in sandpack systems. The history matching technique was employed to estimate relative permeability, fractional flow and saturation profile through the implementation of a Corey-type function. Experimental results showed that in the case of the motor oil being the displaced fluid, the XG 2500 ppm polymer achieved a 47.0% increase in oil recovery compared with the waterflood case, while the XG 1000 ppm polymer achieved a 38.6% increase in oil recovery compared with the waterflood case. Testing with the motor oil being the displaced fluid, the viscosity ratio was 136 for the waterflood case, 18 for the polymer flood case with XG 1000 ppm polymer and 9 for the polymer flood case with XG 2500 ppm polymer. Findings also revealed that for the waterflood cases, the porous media exhibited oil-wet characteristics, while the polymer flood cases demonstrated water-wet characteristics. This paper provides theoretical support for the application of polymer to improve oil recovery by providing insights into the mechanism behind oil displacement. Graphic abstract Highlights The difference in shape of relative permeability curves are indicative of the effect of mobility control of each polymer concentration. The water-oil systems exhibited oil-wet characteristics, while the polymer-oil systems demonstrated water-wet characteristics. A large contrast in displacing and displaced fluid viscosities led to viscous fingering and early water breakthrough.

scholarly journals Photon-magnon response to fluid variability and saturation levels in sandstone reservoirs

2020 ◽  
Vol 17 (6) ◽  
pp. 1065-1074
Author(s):  
Abdullah Musa Ali ◽  
Amir Rostami ◽  
Noorhana Yahya
Keyword(s):  
Oil Recovery ◽  
Relative Permittivity ◽  
Wave Interaction ◽  
Heterogeneous Porous Media ◽  
Injection System ◽  
Bragg Grating ◽  
Fibre Bragg Grating ◽  
Core Flooding ◽  
Oil Saturation ◽  
Fluid Saturation

Abstract The need to recover high viscosity heavy oil from the residual phase of reservoirs has raised interest in the use of electromagnetics (EM) for enhanced oil recovery. However, the transformation of EM wave properties must be taken into consideration with respect to the dynamic interaction between fluid and solid phases. Consequently, this study discretises EM wave interaction with heterogeneous porous media (sandstones) under different fluid saturations (oil and water) to aid the monitoring of fluid mobility and activation of magnetic nanofluid in the reservoir. To achieve this aim, this study defined the various EM responses and signatures for brine and oil saturation and fluid saturation levels. A Nanofluid Electromagnetic Injection System (NES) was deployed for a fluid injection/core-flooding experiment. Inductance, resistance and capacitance (LRC) were recorded as the different fluids were injected into a 1.0-m long Berea core, starting from brine imbibition to oil saturation, brine flooding and eventually magnetite nanofluid flooding. The fluid mobility was monitored using a fibre Bragg grating sensor. The experimental measurements of the relative permittivity of the Berea sandstone core (with embedded detectors) saturated with brine, oil and magnetite nanofluid were given in the frequency band of 200 kHz. The behaviour of relative permittivity and attenuation of the EM wave was observed to be convolutedly dependent on the sandstone saturation history. The fibre Bragg Grating (FBG) sensor was able to detect the interaction of the Fe3O4 nanofluid with the magnetic field, which underpins the fluid mobility fundamentals that resulted in an anomalous response.

Numerical Optimization of WAG Injection in a Sandstone Field using a Coupled Surface and Subsurface Model

2021 ◽  
Author(s):  
Thaer I. Ismail ◽  
Emad W. Al-Shalabi ◽  
Mahmoud Bedewi ◽  
Waleed AlAmeri
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Coupled Model ◽  
Sensitivity Study ◽  
Mobility Control ◽  
Base Case ◽  
The North ◽  
Injection Process ◽  
Interaction Terms ◽  
Wag Injection

Abstract Gas injection is one of the most commonly used enhanced oil recovery (EOR) methods. However, there are multiple problems associated with gas injection including gravity override, viscous fingering, and channeling. These problems are due to an adverse mobility ratio and cause early breakthrough of the gas resulting, in poor recovery efficiency. A Water Alternating Gas (WAG) injection process is recommended to resolve these problems through better mobility control of gas, leading to better project economics. However, poor WAG design and lack of understanding of the different factors that control its performance might result in unfavorable oil recovery. Therefore, this study provides more insight into improving WAG oil recovery by optimizing different surface and subsurface WAG parameters using a coupled surface and subsurface simulator. Moreover, the work investigates the effects of hysteresis on WAG performance. This case study investigates a field named Volve, which is a decommissioned sandstone field in the North Sea. Experimental design of factors influencing WAG performance on this base case was studied. Sensitivity analysis was performed on different surface and subsurface WAG parameters including WAG ratio, time to start WAG, total gas slug size, cycle slug size, and tubing diameter. A full two-level factorial design was used for the sensitivity study. The significant parameters of interest were further optimized numerically to maximize oil recovery. The results showed that the total slug size is the most important parameter, followed by time to start WAG, and then cycle slug size. WAG ratio appeared in some of the interaction terms while tubing diameter effect was found to be negligible. The study also showed that phase hysteresis has little to no effect on oil recovery. Based on the optimization, it is recommended to perform waterflooding followed by tertiary WAG injection for maximizing oil recovery from the Volve field. Furthermore, miscible WAG injection resulted in an incremental oil recovery between 5 to 11% OOIP compared to conventional waterflooding. WAG optimization is case-dependent and hence, the findings of this study hold only for the studied case, but the workflow should be applicable to any reservoir. Unlike most previous work, this study investigates WAG optimization considering both surface and subsurface parameters using a coupled model.

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