Microgels and nanogels used for conformance are trending on some parts of the world. When facing significant permeability contrasts (think 10:1), spot treatments with these particles might be an interesting idea to explore before heading straight into polymer flooding. But this isn’t a simple plug-and-inject operation.
You need to get the (reservoir) details right when considering the size and nature of these microgels. One aspect is that they come as an inverse emulsion, which means a few things.
First, the efficiency of emulsion inversion is impacted by the salinity of the water used for inversion. It’s crucial to factor this into the product design. Get the inversion wrong, and your microgel release won’t be complete.
Next up, the whole emulsion inversion process is sensitive to shear. Transitioning from water-in-oil to oil-in-water means we want those oil droplets to be small. Too big, and they could disrupt the microgel movement or alter the relative permeability more than wanted. Ideally, you would like to push the microgels a bit further from the wellbore. Otherwise, you’re kind of wasting money on microgels when some not-so-clean water might do the job.
Coreflood tests? These are often done under a fixed rate, leading to higher capillary numbers – a situation that’s mostly near the wellbore. When the fluid spreads out and the flow becomes laminar, will the microgels still move effectively as shear drops significantly?
The fact that authors report successful tests (water-cut decrease, oil-cut increase, pressure increase) doesn’t mean that the microgels are working, but that something has changed in the reservoir and has been (partially) blocked. Is it linked to the microgels, the oil, the impact of surfactants on oil, a poor inversion, or a mix of everything is unclear. Would the results be the same by injecting just dirty water with big droplets? Has the microgel propagated far away or is just stuck near wellbore, diverting the fluid around for some time?
I don’t say it is not worth investigating. I just point out the sensitive points for a proper design to achieve what is meant to be: propagating a microgel deep enough to really plug the high permeability layers. Or maybe just to push it far enough so that water can be diverted in other zones, assuming crossflow is not a dominant mechanism.
Microgels can work well to isolate specific zones in the near wellbore during WSO treatments if the flow regime has been properly diagnosed.
Personally, I would avoid considering these technologies in very low permeability reservoirs, except If the highest permeability layer is in the 500mD+ range. In these cases, polymer flooding should do a great job correcting conformance.
I have put below an old review of the literature on the flow of emulsions in porous media. You will see that people used dirty water for conformance a long time ago. It’s always good to review the basics before choosing a technology.
Multiphase flow at pore scale
When a wetting and a non-wetting phase flow together in a porous rock, each phase follows separate and distinct paths. At any saturation of the two phases, a certain number of pores are available for passage of the wetting phase while the remainder is able to pass only the non-wetting phase. Pores passing the non-wetting phase also contain some wetting phase (usually the connate water). The changing effect of saturation of one fluid is to open more pores to flow of the phase whose saturation is increased and, conversely to decrease the number of pores available for the passage of the second phase. When two fluids flow simultaneously, they interfere. The consequence is the decrease of the sum of the two effective permeabilities to a value less than the absolute permeability. In other words, the sum of the two relative permeabilities is always less than unity.
The ease with which a phase can flow depends on:
- The size of the pore throats
- The number of pores occupied by the phase
- The probability that these pores are hydraulically interconnected
The first two factors depend on the pore throat size distribution and the wetting ability of the phase with respect to the rock surface. The last factor is governed by the extent to which the phase saturates the porous media. There are two limits. The one occurs when the non-wetting phase saturation is so high that the wetting phase is reduced to an irreducible saturation. At this point, the probability of finding interconnected pores able to pass the wetting phase is negligible. Thus the hydraulic conductivity is lost and the relative permeability to the phase becomes zero. The second limit is analogous to the first and occurs when the non-wetting phase saturation is so small that relatively few pores will be interconnected, no flow of the non-wetting phase can occur and the relative permeability to the phase is zero.
Mathematically, this is described by applying Darcy’s law to each phase.
Capillary doublet: bubble genesis and Jamin effect
Let’s consider a piece of porous medium made of two pores: one is thin, the other one is big. Both are set up in parallel (capillary doublet). We consider a water wet case.
Water that is slowly injected pushes the oil out of the pores with an ease that increases in small pores thanks to the capillary effect that comes on top of other forces.
The water-oil interface (meniscus) gets ahead in the smallest pore and reaches the exit of the capillary doublet first. A second interface appears in the bigger pore, the so-formed oil droplet can travel in the pore or remain trapped in the porous medium (Jamin effect).
Jamin effect:
The oil droplet will soon or later encounter a pore throat and, depending on the pressure gradient, will remain blocked a the throat entrance.
We can write that the pressure is the same on a AB horizontal line as shown below:
With: θ = contact angle (function of wettability); σ= IFT (dynes/cm)
This is the pressure difference necessary to push the oil droplet through the pore throat. For example, if:
r = 0.5 µm
R = 5µm
σ*cosθ= 30 dyn/cm (1 dyn/cm = 10-3 N/m)
Then PA-PB= 1.08.105 Pa (around 1 bar)
One can see that the pressure gradient necessary to unblock the oil droplets can be quite high. If less than this value, the oil droplet will remain stuck. This could be often the case since pressure gradients linked to production are close to 1bar/10m and more rarely 1bar/m.
The formula used to obtain a rough idea of the pore throat radius is:
Bibliography & Synthesis
Cartmill carried out experiments on the flow of stable crude oil-in-water emulsions through packed beads having differing permeability zones in series. He found that considerable amounts of oil droplets were retained at the junction of different permeability zones, with maximum retention at the front portion of the low permeability zone.
McAuliffe conducted laboratory studies to show that oil-in-water emulsions can be used as a selective plugging agent to improve oil recovery in water floods. The result from injecting caustic oil-in-water emulsions with various droplet sizes into Berea sandstone under a constant pressure showed a larger reduction in water permeability to the sandstone with larger drop size to initial permeability ratio. Furthermore, permanent permeability reduction was observed even when many pore volumes of water followed the emulsion. He also suggested that for an emulsion to be the most effective, the droplets of oil in the emulsion should be slightly larger than the pore-throat constrictions in the porous medium. Later, field tests substantiated the laboratory observations. Oil-in-water emulsions were found to reduce water channeling from injection to production wells, thus increasing oil recovery, lowering water-oil ratios, and considerably increasing the volumetric sweep efficiency.
Soo and Radke studied experimentally the flow mechanism of dilute, stable oil-in-water emulsions in porous media by determining the transient permeabilities, the pore size distribution of the porous medium, and the inlet and effluent droplets concentrations and size distributions. This is the only other study found in the literature that investigated the oil droplet migration in a porous medium by means of a visual micro-model. They argued that dilute, stable oil-in-water emulsions did not flow in porous media as continuous, viscous liquids being squeezed through pore constrictions; rather, they flowed by the capture of the dispersed phase with a subsequent reduction of permeability to the continuous phase. They claimed that this droplet capture mechanism was found to be similar to a filtration process.
Khambharatana et al. studied the physical mechanisms of stable emulsion flows in Berea sandstone and Ottawa sand packs for systems of comparable droplet and pore sizes. Their results showed that the change in emulsion rheology in a porous medium has an overall trend similar to that in a viscometer for the shear rates of interest. Furthermore, the emulsion droplets were found to be captured according to a filtration process.
Mendez investigated the mechanisms of permeability impairment caused by the flow of oil in-water emulsions into cores containing residual saturation. She reported that the permeability decline occurred in two stages, one associated with the injected droplets followed by the second during which generation of droplets played an important role. The experimental results indicated that the presence of residual oil had a profound effect on the measured permeability decline.
Devereux proposed a droplet retardation model, based on the mechanism postulated by McAuliffe, for describing the flow of stable oil-in-water emulsions in porous media, including capillary effects, but neglecting gravitation and compression. Devereux considered the flow of two phases, one dispersed and one continuous, in porous solids with the capillary effect included. He proposed that the emulsion droplets flowed slower than the continuous phase because of a capillary resistance force encountered during their flow through smaller pore throats. Therefore, this capillary retarding force, which depends on the droplet size distribution, was included in the pressure driving force of the dispersed oil phase in this model.
Soo and Radke proposed a flow model describing the flow of stable, dilute emulsions in unconsolidated porous media based on deep-bed filtration concepts. In the model, transient flow behavior was characterized by three parameters: a filter coefficient, a flow-redistribution parameter, and a flow restriction parameter. The filter coefficient controlled the sharpness of the emulsion front. The flow-redistribution parameter dictated the steady-state retention as well as the flow redistribution phenomenon. The flow-restriction parameter described the effectiveness of the retained drops in reducing permeability. Comparisons among the filtration model and the previously developed emulsion flow models showed that the filtration model successfully represented the experimental observations, such as permanent permeability reduction.
However, the model did not properly relate the proposed 3 parameters to the physical properties of the mobile and stationary phases, in particular the emulsifier concentration and the porous medium wettability. In summary, in order to quantify the flow behavior of dilute stable emulsions through a porous medium, an emulsion can be considered to flow as a homogeneous phase in the event that oil droplets are much smaller than pore throat openings. Under some conditions this might be a reasonable approximation and the flow behavior could be predicted reasonably from Darcy’s Law as long as the transient rheological properties of the flowing emulsions applied correctly for the given shear rates. However, with the increase of droplet diameter relative to the pore throat diameter, the movement of a droplet should decrease markedly at some critical limit, which is a function of the internal pressure of the droplet relative to that of the water phase. The pressure gradient across each strained droplet can be predicted from the Young-Laplace equation also described in the first paragraph of this review:
Pc=2γcosθ/r
where:
Pc = capillary pressure [Pa]
γ = oil-water interfacial tension [mN/m], sometimes written
θ = porous medium wettability [dimensionless]
r = droplet radius [m]
So far, all available models on emulsion flow through porous media are either neglecting the effect of capillary pressure across a single pore or simply assuming it to be constant.
Although such assumption could be reasonably justified for a highly stable diluted emulsion, it could be completely misleading for predicting the flow behavior of highly concentrated emulsions, especially those carrying less concentrated surfactants. The neglected consideration is mainly related to the emulsion quality associated with the transition from Newtonian to non-Newtonian rheological behavior which is dependent on the surfactant (emulsifier) concentration and the local applied shear rate. Surfactants reduce the interfacial tension between oil and water by adsorbing at the liquid-liquid interface allowing easier spreading. They also accumulate at the droplets’ surface in an emulsion and form a protective layer in the form of a tough, elastic film that is not broken when droplets collide.
Careful investigation of the Young-Laplace equation shows that oil droplets-to-water interfacial tensions and the droplets’ radii cannot be assumed to be constant during an emulsion flow into a porous medium. In fact, they are strong functions of the surfactant type and concentration present in the aqueous phase.
It is believed that, as the emulsion propagates into a porous medium, more surfactant will be adsorbed onto the surface of the sand grains, resulting in the reduction of surfactant concentration within the emulsion. Therefore, droplets may coalesce more easily and produce larger droplets when the surfactant concentration in solution is below the minimum limit.
Moreover, droplets may coalesce because of the application of high shear forces rupturing the interface film while droplets are being forced toward each other. In the case of emulsions having high oil content, in which the droplet-droplet interactions are of significance, the latter effects may be more pronounced. Any decrease in surfactant concentration may eventually lead to droplet coalescence while the droplets percolate in the porous medium. Moreover, the wettability of a porous medium (cosθ in above equation) is a strong function of solution pH. The elasticity of the film at the oil droplets-water interface can be affected at the same time by any change in solution pH. Thus, the internal pressure of an oil droplet in an aqueous solution, which is a function of its radius and interfacial tension, may be modified so that a droplet may be carried more or less easily through a rock matrix. In the event that each pore is occupied by a highly viscous droplet(s) which is larger than the pore throat, the emulsion flow should be severely constrained provided that the pressure gradient does not exceed the critical gradient beyond which the droplet jumps to the next pore. Such occupation results in an overall increase of the pressure gradient across the porous medium. Any further increase in the local net pressure across the occupied pores results in the coalescence of the occupied droplets in each pore providing a very stable “plug” in the matrix requiring a large pressure gradient (several hundreds of kPa/m) to cause its displacement.
Example: Experiments carried out by Zeidani et al., 2007.
Three different O/W emulsions were prepared and utilized in this part of experiments. The first two, denoted M/W1 and M/W2, were prepared by mixing mineral oil in distilled water. Emulsion M/W2 was prepared by the hand shaking method. The other one, called LM/W1, was made of a Lloydminster oil in distilled water. The phase ratio for all three emulsions was
5% oil and 95% water with a surfactant concentration of 0.12% (volume/volume), which corresponds to 0.13 grams of surfactant in 100 cm3 of water (0.13% weight/volume). The mean droplet size for emulsions M/W1, M/W2 and LM/W1 was measured to be 5.1, 121, and 4.5 μm, respectively.
Fine emulsion M/W1 was injected into the micro-model under variable flow rate conditions. The emulsion mean droplet size was smaller than the pore throat size by an order of magnitude. It was observed that all droplets passed through the pore throat network easily under high flow rate conditions. However, at lower flow rates of 3 cm3/min, droplets were deposited in the pore crevices and captured mainly on the pore surfaces very close to the pore throat entrances. It was observed that droplets accumulated on top of each other, coagulated and thereby blocked the pore throats.
When the coarse emulsion M/W2 was injected into the micro-model, most of the droplets were strained into pore throats which had a smaller diameter compared to the droplets’ size. As the emulsion injection continued, pores were occupied with more droplets and, under higher pressure build-up, the droplets were squeezed through the throats to the next pores downstream. The droplets showed high stability. Emulsion LM/W1, which carried more viscous droplets compared to the two previous emulsions, showed a relatively different behavior during its injection. It was observed that these highly viscous droplets were deposited in the pore crevices and captured mainly on the pore surfaces very close to the pore throat entrances. It was observed that droplets accumulated on top of each other, coalesced and produced larger immobile droplets. It seemed that these highly viscous oil droplets were attached to the pore surface strongly enough so that they were able to resist the local shear forces and block the pores completely. The pressure profile for these three experiments shows that an emulsion, which carried more viscous oil droplets, may resist higher pressures. Also, the flow through the porous medium of the emulsions prepared with the same oil type resulted in higher pressure drops for the one with larger droplet sizes compared to the one with smaller droplet sizes.
It was expected that applying the alkaline pre-flush solution would shift the wettability toward a highly water-wet system, which would ease the passage of the oil droplets through the pores, while the acidic pre-flush solution would result in an oilwet system. Although there was no direct method of measuring the wettability changes, it was observed that the alkaline preflush did not enhance the droplets penetration depth. However, the acidic pre-flush solution increased the droplets penetration depth by 100% compared to the base case. This was contrary to our prediction since the pre-flush solutions affected not only the wettability but also the stability of the interfacial film. It was observed that the alkaline pre-flush solution caused the droplets to retain their stability. On the other hand, the acidic pre-flush solution resulted in destroying the interfacial film, and then breaking up and coalescing the droplets. It can be concluded that, for a comparable system of highly viscous droplets and pore throat sizes, an alkaline pre-flush may enhance the penetration depth while an acidic pre-flush would reduce the droplets advancement into the pores because of their coalescence.
In addition, it was observed that a surfactant pre-flush solution caused the droplets to be squeezed through easier and move faster into the pore network. It increased the penetration depth by 267% compared to the base case. If you have injected commercial microgels and the company proposed to co-inject a surfactant, that’s the reason 🙂
References
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BAHADORI, A. AND ZEIDANI, K., Predicting electrostatic desalter performance; paper CIPC 2005- 093, Proceedings Canadian International Petroleum Conference, 56th Annual Technical Meeting of Petroleum Society of CIM, Calgary, AB, 7-9 June 2005
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