Existing reservoirs surfactants

Surfactants provide temporary emulsion droplet stabilization of monomer droplets in tire two-phase reaction mixture obtained in emulsion polymerization. A cartoon of tliis process is given in figure C2.3.11. There we see tliat a reservoir of polymerizable monomer exists in a relatively large droplet (of tire order of tire size of tire wavelengtli of light or larger) kinetically stabilized by surfactant. 

Effect of Ca2. In many reservoirs the connate waters ontain substantial quantities of divalent ions (mostly Ca . In alkaline flooding applications at low temperatures, the presence of divalent ions leads to a drastic increase in tensions r35,36]. Kumar et al. f371 also found that Ca and Mg ions are detrimental to the interfacial tensions of sulfonate surfactant systems. Detailed studies at elevated temperatures appear to be non-existent. 

Petroleum production from subterranean reservoirs can be increased by injecting water as liquid or steam. Various chemicals have been added to the water or steam to increase volumetric sweep efficiency. One alternative is the use of emulsions which serve as diverting agents to correct the override and channeling problems that occur during fluid injection. Laboratory results show that it may be possible to control channeling and steam override with an emulsion blocking technique. The emulsion can be formed with the aid of a surfactant mixture or by use of natural surfactants that exist in some crude oils. Core-... 

Many important industrial systems make extensive use of surfactants for various reasons. Surfactants may dissolve in the bulk liquid phases, form distinct micelles, or preferentially concentrate on the interfaces. Existing flash algorithms do not address micelles or interfaces as possible reservoirs for the surfactants. The flash results are simply not valid for systems with surfactants. 

Almost all chemical EOR applications have been in sandstone reservoirs, except a few stimulation projects and a few that have not been published have been in carbonate reservoirs. One reason for fewer applications in carbonate reservoirs is that anionic surfactants have high adsorption in carbonates. Another reason is that anhydrite often exists in carbonates, which causes precipitation and high alkaline consumption. Clays also cause high surfactant and polymer adsorption and high alkaline consumption. Therefore, clay contents must be low for a chemical EOR application to be effective. 

Simulation results from Pope et al. (1979) showed that the best oil recovery for a given amount of injected surfactant occurred where a salinity higher than the optimum existed downstream of the slug and a salinity lower than the optimum existed upstream of the slug (in the polymer drive) and the slug itself traversed as much of the reservoir as possible in the low-tension type III environment. Generally, the chemical slug is small. Therefore, the initial and drive salinities matter most. Pope et al. observed that the low final salinity promoted low final retention of surfactant. 

The preceding four types of consumption mnst be determined experimentally in the laboratory and upscaled to field scales. The experimental conditions should be as close to the field conditions as possible. Field oil and water samples can be obtained, and experiments shonld be condncted at the held temperature. Ideally, reservoir rocks should be used. In practice, we may not be able to conduct all the necessary experiments becanse of the cost, available resources, and limited time. An approximation mnst be made to estimate the consumption for each type. For example, the consnmption for alkali reaction with crude oil can be estimated from Eq. 10.12, assnming all the acidic components are consumed to react with the alkali. The alkali consumption ACo in meq/mL is the same as the soap generated. ACo is generally a small fraction of the total consumption. Because these consumptions involve complex chemical reactions, efforts have been made to collect some published experimental data and were presented earlier. A general rule is 0.05 to 2% alkali concentration and 0.1 to 0.23 PV injection volnme. Note that alkali addition in an ASP system can rednce snrfactant and polymer adsorption. However, addition of snrfactant and/or polymer does not affect alkali consumption (Li, 2007). This is probably because the alkali molecules are smaller than the surfactant or polymer molecules, thus the existence of snrfactant and polymer molecnles will not affect the adsorption of alkali molecnles, nor will their existence affect alkahne reactions. 

It is commonly known that the constituents of a micellar slug may interact in several ways with both the rock and the formation fluids when injected into a reservoir, and a considerable body of literature exists (1-8). In spite of this knowledge, however, it is not yet possible to design a micellar slug for tertiary oil recovery from basic principles because of the complexity of the phenomena and inadequate understanding of the processes involved. The primary objectives of this paper are to present the results of some experiments on the structure and mineralogy of selected rock and reservoir core samples, on the interactions within surfactant solutions and between surfactant solutions and rock, and to attempt to draw from these observations some conclusions as to the phenomena and mechanisms involved-especially surfactant loss processes-as these can affect the maintenance of low interfacial tension between oil and water. 

A similar situation exists in regard to other properties when there is no accepted theory by which they can be explored in advance. Among these is the simple question of a surfactant s ability to stabilize the lamellae against coalescence. Again, one can only accept experimental determinations of this capability if the work is done in conditions that duplicate the reservoir environment. The ionic and other chemical conditions are also of major importance. 

Steam-based processes in heavy oil reservoirs that are not stabilized by gravity have poor vertical and areal conformance, because gases are more mobile within the pore space than liquids, and steam tends to override or channel through oil in a formation. The steam-foam process, which consists of adding surfactant with or without noncondensible gas to the injected steam, was developed to improve the sweep efficiency of steam drive and cyclic steam processes. The foam-forming components that are injected with the steam stabilize the liquid lamellae and cause some of the steam to exist as a discontinuous phase. The steam mobility (gas relative permeability) is thereby reduced, and the result is in an increased pressure gradient in the steam-swept region, to divert steam to the unheated interval and displace the heated oil better. This chapter discusses the laboratory and field considerations that affect the efficient application of foam. 

Foam Effectiveness in Porous Media. No generally accepted correlations exist between foam characteristics measured outside the porous medium and foam effectiveness as a gas mobility-reducing agent in porous media. The performance of the nine surfactants that passed the solubility criteria was therefore evaluated in porous media under typical reservoir conditions. The results of such an evaluation can be expressed in several ways. One of the simplest measures of foam effectiveness, and arguably the most straightforward one, is the mobility-reduction factor (MRF). The MRF is defined as the ratio of pressure gradients across a... 

Temperature gradients exist in a reservoir that has been subjected to steam-flooding, and therefore, a knowledge of the dependence of surfactant adsorption on temperature is important in the evaluation of steam-foam processes. Low adsorption levels in high-temperature or swept zones are beneficial to process performance because gas mobility reduction or gas blockage in the swept zones is desired. 

Thus the experimental data appear to show that silica coated micelles can exist in solution and can either participate directly in forming mesos-tructures via coalescence or else play a minimal role as a surfactant/ silica oligomer reservoir while structure develops in a concentrated phase-separated gel phase which initially is formed from spherical or... 

Most studies in the literature with surfactants focus on the important aspect of reducing liquid interfacial tensions, nonetheless, understanding the role that surfactants can have to alter wettabibty is of equal importance. As an example, some researchers [73] have reported that maximum oil recovery occurs near neutral wettabibty. In actuabty, the optimum wettabibty condition for maximum oil recovery depends upon numerous factors and can vary from reservoir to reservoir [74], Surfactants provide an opportunity to modify reservoir wettabibty for maximum secondary or tertiary oil recovery. Other opportunities exist to improve drilling, etc. This section provides laboratory studies and field examples of wettabibty alteration by surfactants in porous media. 

Recent laboratory studies have demonstrated the potential utility of borates as alkaline agents in chemical enhanced oil recovery. Compared with existing alkalis, sodium metaborate has an unusually high tolerance toward the hardness ions, Ca + and Mg +, paving the way for the implementation of alkali-surfactant-polymer floods for the large number of high-hardness saline carbonate reservoirs. In the absence of surfactants, borate solutions exhibit a strong tendency for spontaneous imbibition, or uptake into oil-wet or mixed-wet carbonate cores, with consequently improved recovery of oil compared with solutions of other salts and alkalis. 

At the end of this injection schedule, a second downhole pressure-transient test was performed to verify that mobility reduction existed deep into the reservoir. Polymer injection at 513 B/D resumed for 2 days to ensure that well impairment had not occurred as a result of the pressure-transient test. Following this period, surfactant, alkali, and polymer were injected at a rate of 514 B/D for a total of 30 days. 

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