CO and Flue Gas Sequestration During Tertiary Oil Recovery: Optimal Injection Strategies and Importance of Operational Parameters

2005 ◽  
Author(s):  
J.J. Trivedi ◽  
T. Babadagli
Keyword(s):  
Oil Recovery ◽  
Flue Gas ◽  
Operational Parameters ◽  
Tertiary Oil Recovery ◽  
Optimal Injection ◽  
Injection Strategies

Optimal Injection Strategies for the Propagation of Surfactant Mixtures Through Porous Media

1984 ◽  
Vol 24 (05) ◽  
pp. 545-554 ◽  
Author(s):  
Jeffrey H. Harwell ◽  
Robert S. Schechter ◽  
William H. Wade
Keyword(s):  
Molecular Weight ◽  
Porous Media ◽  
Oil Recovery ◽  
Chromatographic Separation ◽  
Surfactant Solution ◽  
Commercial Application ◽  
Recovery Efficiency ◽  
Surfactant Mixtures ◽  
Optimal Injection ◽  
Injection Strategies

Abstract The chromatographic movement of surfactant mixtures through porous media is examined to determine possible injection strategies for minimizing the amount of surfactant required in a tertiary oil recovery chemical flood. The model used does not consider the presence of oil but does account for mixed micelle formation. Expressions are derived that represent the surfactant required to expose an entire reservoir to an "effective oil recovery mixture." This effective mixture may be either one whose overall composition is within prescribed limits of the composition of the injected surfactant solution or it may be a mixture whose overall composition varies but which contains micelles of fixed composition. Mixtures considered contain cosolvents and one, two, or three surfactant components. Initial calculations neglect dispersion, but numerical calculations including dispersion leave the conclusion unchanged; within the limitations of the model, there are optimal strategies for the propagation of surfactant mixtures through porous media. The optimal injection strategy varies, depending on the nature of the surfactant solution injected into the porous medium. Conditions for and the location of the optimum are discussed. Conclusions based on observations about these systems then are extended to cover the injection of surfactant mixtures currently available commercially. Introduction Commercial application of surfactants for EOR now appears feasible. The principle at work in such processes is the lowering of interfacial tension (IFT) between the continuous flowing water and trapped residual oil droplets to allow the oil to be mobilized. Mixtures that effectively lower oil/water IFT are often blends of various surfactant types, isomers of the same surfactant, and/or cosurfactants in an electrolyte solution. The oil recovery efficiency of the injected mixture generally is quite sensitive to changes in mixture composition. Change of composition after injection into the reservoir may occur by one or a combination of mechanisms. For example, the mixture components may partition selectively into the various phases present in the reservoir. The mechanism considered here is the chromatographic separation of the mixture into its components due to preferential adsorption of various components onto reservoir minerals-"the chromatographic problem." The recent reports of the Bell Creek Unit A micellar/polymer pilot showed 20% of the injected surfactant produced before any oil bank with negligible concomitant incremental tertiary oil production. Significantly, the surfactants produced were the lower-molecular-weight species. Though alternative mechanisms for this separation yet may be established, the hypothesis of chromatographic separation of the components in the mobile aqueous phase seems adequate. Not only did this produced surfactant not result in enhanced recovery, but since the injected solution was designed to give ultralow IFT's with the low-molecular-weight components in place, it seems likely that the oil recovery efficiency of the remaining surfactant also may have been impaired. These results emphasize the importance of understanding the mechanisms of surfactant chromatographic movement. One means of combatting the chromatographic problem is to reduce the local adsorption of the mixture components-that is, modify the adsorption isotherms of the constituents. This may be done either by changing the reservoir minerals (e.g., by a caustic flood) or by modifying the structure of the surfactant molecules. A complementary approach is to examine the dynamics of the chromatographic movement of surfactant mixtures to identify injection strategies, if they exist, that minimize the total surfactant requirement. It is this question that is considered here. The analysis considers an oil-free linear system and neglects many of the complex features that are encountered in an actual chemical flood. There are several reasons for ignoring these complicating factors. The coherence solutions apply to the systems considered here; whereas the only solutions that include the presence of oil employ numerical computations. An analytical solution is desirable; however, there is an additional more compelling argument that has been used to justify neglecting the presence of oil. The chromatographic movement of a surfactant/ cosurfactant mixture through an oil-free core should demonstrate the qualitative features of the actual oil recovery process. While multiple flowing phases do arise in an actual flood, the released oil forms a bank ahead of the surfactant slug. SPEJ P. 545^

Optimal Injection Policies for Enhanced Oil Recovery: Part 2-Surfactant Flooding

1984 ◽  
Vol 24 (03) ◽  
pp. 333-341 ◽  
Author(s):  
Zohreh Fathi ◽  
Fred W. Ramirez
Keyword(s):  
Oil Recovery ◽  
Return On Investment ◽  
Volumetric Flow Rate ◽  
Commercial Application ◽  
Type B ◽  
Surfactant Flooding ◽  
Tertiary Oil Recovery ◽  
Optimal Injection ◽  
Surfactant Systems ◽  
The Cost

Abstract The optimal control theory of distributed-paranieter systems has been applied to the problem of determining the best injection policy of a surfactant slug for a tertiary oil recovery chemical flood. The optimization criterion is to maximize the amount of oil recovered while minimizing the chemical cost. A steepest-descent gradient method was used as the computational approach to the solution of this dynamic optimization problem. The performance of the algorithm was examined for the surfactant injection in a one-dimensional flooding problem. Two types of interfacial tension (IFT) behavior problem. Two types of interfacial tension (IFT) behavior were considered. These are a Type A system where the IFT is a monotonically decreasing function with solute concentration and a Type B system where a minimum IFT occurs at a nominal surfactant concentration. For a Type A system, the shape of the optimal in 'faction strategy was not unique, however, there is a unique optimum for the amount of surfactant needed. For a Type B system, the shape of the optimal injection as well as the amount injected was unique. Introduction Surfactant recovery systems are being investigated by the petroleum industry as a means of increasing the petroleum supply. Commercial application of any petroleum supply. Commercial application of any surfactant flooding process relies upon economic projections that indicate a decent return on investment. projections that indicate a decent return on investment. Previously. surfactant systems for tertiary oil recovery have been optimized by adjusting concentrations of individual components empirically. Salinity has been shown to be an important variable in surfactant system optimization. The particular choice of surfactant and cosurfactant has been studied by Salager et al. Multivariable optimization of surfactant systems based on minimizing the IFT has been studied by Vinatiere et al. As reported, such an optimization may or may not coincide with optimal oil recovery since low IFT is a necessary. but not a sufficient condition for achieving, high displacement efficiency. Chemical supply and cost are important parts of economic projections. Because of the high cost of chemicals, it is essential to optimize surfactant systems to provide the greatest oil recovery at the lowest cost. In this paper, an optimization surfactant is taken as the minimization of the chemical cost and maximization of the recovered oil. The goal is to determine the best way of injecting a surfactant slug into the reservoir formation. Mathematical Formulation of the Performance Index Performance Index We desire to obtain maximum oil recovery with a minimum amount of chemical surfactant injected. These objectives can he expressed in a quantitative form through the formulation of a cost functional. J', which is to be minimized, where J' equals the cost of surfactant injected minus the value of oil recovered. This descriptive statement of the cost functional must be translated into a mathematical form to use quantitative optimization techniques. The oil value can be formulated as (1) where C1 = cost of oil per unit volume ($251.6/m 3[$40/bbl]),= volumetric flow, rate of oil at the coreoutlet L = core length, and a = time. The chemical cost is expressed mathematically as (2) where C2 = chemical cost per unit weight ofsurfactant ($5.45 × 10–3/g [$2.47/lbm]), Cs( ) = surfactant concentration of the injectedfluid in weight fraction, P slug = slug density ( 1 g/cm 3 ). and Qw, ( ) = volumetric flow rate of water at thecore inlet. The objective functional is, therefore, (3) JPT P. 333

scholarly journals Optimal Control of Polymer Flooding Based on Maximum Principle

2012 ◽  
Vol 2012 ◽  
pp. 1-20 ◽  
Author(s):  
Yang Lei ◽  
Shurong Li ◽  
Xiaodong Zhang ◽  
Qiang Zhang ◽  
Lanlei Guo
Keyword(s):  
Optimal Control ◽  
Maximum Principle ◽  
Oil Recovery ◽  
Polymer Concentration ◽  
Inequality Constraint ◽  
Polymer Flooding ◽  
Polymer Injection ◽  
Flow Equations ◽  
Optimal Injection ◽  
Injection Strategies

Polymer flooding is one of the most important technologies for enhanced oil recovery (EOR). In this paper, an optimal control model of distributed parameter systems (DPSs) for polymer injection strategies is established, which involves the performance index as maximum of the profit, the governing equations as the fluid flow equations of polymer flooding, and the inequality constraint as the polymer concentration limitation. To cope with the optimal control problem (OCP) of this DPS, the necessary conditions for optimality are obtained through application of the calculus of variations and Pontryagin’s weak maximum principle. A gradient method is proposed for the computation of optimal injection strategies. The numerical results of an example illustrate the effectiveness of the proposed method.

scholarly journals INJEKSI FOAM SEBAGAI TERTIARY OIL RECOVERY

PETRO ◽  
2019 ◽  
Vol 8 (2) ◽  
pp. 51
Author(s):  
Iwan Setya Budi ◽  
Agus Rudiyono ◽  
Astra Pramana Astra Pramana
Keyword(s):  
Oil Recovery ◽  
Flue Gas ◽  
Gas Injection ◽  
Sweep Efficiency ◽  
Gas Reservoir ◽  
Recovery Method ◽  
Tertiary Oil Recovery ◽  
Hydrocarbon Gas ◽  
Tertiary Recovery ◽  
Reduce Carbon Emission

<p><em>Foam injection is a variance of gas flood as tertiary recovery method designed to mitigate low sweep efficiency normally found in gas flood due to inheritance of density difference between injected gas and oil which often severed by presence of reservoir heterogeneity (permeability contrast in this case). Foam EOR has two goals: (1) improve oil recovery by promoting better sweep efficiency, and (2) reduce carbon emission related to global warming issue provided that the injectant gas used is CO2, hydrocarbon gas or flue gas.. Reservoir simulation performed is able to show recovery improvement of foam compared to continuous gas injection.</em></p>

The Mechanism of Flue Gas Injection for Enhanced Light Oil Recovery

2004 ◽  
Vol 126 (2) ◽  
pp. 119-124 ◽  
Author(s):  
O. S. Shokoya ◽  
S. A. (Raj) Mehta ◽  
R. G. Moore ◽  
B. B. Maini ◽  
M. Pooladi-Darvish ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Flue Gas ◽  
Gas Injection ◽  
Cost Effective ◽  
Air Injection ◽  
Oil Reservoirs ◽  
Flue Gases ◽  
Low Permeability ◽  
Light Oil ◽  
Light Oil Reservoirs

Flue gas injection into light oil reservoirs could be a cost-effective gas displacement method for enhanced oil recovery, especially in low porosity and low permeability reservoirs. The flue gas could be generated in situ as obtained from the spontaneous ignition of oil when air is injected into a high temperature reservoir, or injected directly into the reservoir from some surface source. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible or near–miscible with the reservoir oil, thereby displacing it more efficiently than an immiscible gas flood. Some successful high pressure air injection (HPAI) projects have been reported in low permeability and low porosity light oil reservoirs. Spontaneous oil ignition was reported in some of these projects, at least from laboratory experiments; however, the mechanism by which the generated flue gas displaces the oil has not been discussed in clear terms in the literature. An experimental investigation was carried out to study the mechanism by which flue gases displace light oil at a reservoir temperature of 116°C and typical reservoir pressures ranging from 27.63 MPa to 46.06 MPa. The results showed that the flue gases displaced the oil in a forward contacting process resembling a combined vaporizing and condensing multi-contact gas drive mechanism. The flue gases also became near-miscible with the oil at elevated pressures, an indication that high pressure flue gas (or air) injection is a cost-effective process for enhanced recovery of light oils, compared to rich gas or water injection, with the potential of sequestering carbon dioxide, a greenhouse gas.

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