An Innovative Acid Diversion Using In-Situ Foam Generation: Experimental and Successful Field Application

In carbonate reservoirs, effective acid stimulation is essential to overcome reservoir damage and mainline high oil production. Recently, most of oil wells are being drilled horizontally to maximize production. Acid stimulation of horizontal wells with long intervals require very effective acid diversion system. If the diversion system is not efficient enough, most of the acid will be leaking-off near the casing shoe, in openhole well, which will result in a fast water breakthrough and diminish production. This study describes a breakthrough treatment for acidizing long horizontal wells in carbonate formations. The novel technology is based on in-situ foam generation to divert the acid. Gas diversion, as a foam, is a perfect diversion mechanism as gas creates pressure resistance which forces the acid stages to be diverted to new ones?. The diversion will not require the acid to be spent, compared to viscoelastic diverting system. Moreover, no gel is left behind post treatment, which will eliminate any damage potential. The system is not impacted with the presence of corrosion products, where diverting system will not function without effective pickling and tubular cleanup. Lab results showed that the new in-situ foam generation system was very effective on both dolomite and calcite cores. The system creates high back pressure when foam is generated, which significantly diverts the acid stages to stimulate other intervals. Moreover, the new system minimizes acid leak-off and penetration. Open completing the job, the foam collapse leaving no left behind any damaging material. Field application of the in-situ foam generating system showed high success rate and outperformed other diversion mechanisms. The well gain was up to 18 folds of the original well injectivity.

Supercritical CO2-Foam Screening and Performance Evaluation for CO2 Storage Improvement in Sandstone and Carbonate Formations

Injecting carbon dioxide (CO2) as foam during enhanced oil recovery (EOR) can improve injectate mobility and increase sweep efficiency. Integrating CO2-foam techniques with carbon capture, utilization and storage (CCUS) operations is of recent interest, as the mobility control and sweep efficiency increases seen in EOR could also benefit CO2 storage during CCUS. In this study, a variety of different charge, hydrocarbon chain length, head group surfactants were evaluated by surface tension, bulk and dynamic CO2-foam performance assessments for CCUS. The optimal foam candidate was expected to provide satisfying mobility control effects under reservoir conditions, leading to an improved water displacement efficiency during CO2-foam flooding that favors a more significant CO2 storage potential. All tested surfactants were able to lower their surface tensions against scCO2 by 4-5 times, enlarging the surface area of solution/gas contact; therefore, more CO2 could be trapped in the foam system. A zwitterionic surfactant was found to have slightly higher surface tension against CO2 while exhibiting the highest foaming ability and the most prolonged foam stability with a relatively slower drainage rate among all tested surfactants. The dynamic performance of scCO2-foam stabilized by this zwitterionic surfactant was also evaluated in sandstone and carbonate cores at 13.79 MPa and 90°C. The results show that the mobility control development in carbonate core was relatively slower, suggesting a gradual foam generation process attributed to the higher permeability than the case in sandstone core. A more significant cumulative CO2 storage potential improvement, quantified based on the water production, was recorded in sandstone (53%) over the carbonate (47%). Overall, the selected foam has successfully developed CO2 mobility control and improved water displacement in the occurrence of in-situ foam generation, hence promoting the storage capacity for the injected CO2. This work has optimized the foaming agent selection method at the actual reservoir conditions and evaluated the scCO2-foam performance in establishing high flow resistance and improving the CO2 storage capacity, which benefits integrated CCUS studies or projects utilizing CO2-foam techniques.

Evaluation of In-Situ Generation of Nitrogen Gas for Foam Applications using Two Salt Solutions

Foams are used in many oil and gas applications including conformance control during EOR processes, fracturing, and acidizing operations. Foams are defined as dispersions of gas bubbles into a continuous liquid phase. Typically, foams are generated when an injection gas such as nitrogen, carbon dioxide, or flue gas is mixed with an injection fluid containing a foaming agent. This method, however, requires a gas source to be present for foams to be generated. The objective of this study is to evaluate a new alternative technique for foam generation using two salt solutions. Nitrogen gas is generated as a result of the reaction of the two salt solutions at specific conditions. This generated nitrogen gas is then used for foam generation in porous media. The foam generated using the two salt solutions is tested in a microfluidic device (rock-on-a-chip) to study the gas mobility reduction in porous media. A Foam rheometer apparatus is also used to measure foam apparent viscosity when the two salt solutions are mixed with a foaming agent. The results are compared with those obtained when nitrogen gas is injected into the system independently in the absence of the two salt solutions. Results reveal that the amount of added salts significantly impact the produced nitrogen volume. Additionally, the test conditions especially the temperature, significantly impacts the reaction rate. The rate of nitrogen gas generation is directly proportional to the temperature when tested at 25-80°C. In addition, experiments demonstrate that the foams generated using the two salt solutions reaction have almost identical characteristics as those produced when nitrogen gas is injected into the foam rheometer apparatus independently. Both methods generate the same foams with comparable foam apparent viscosity. In the microfluidic system, the foam obtained using the two salt solutions in the presence of a foaming agent shows excellent resistance to gas flow and subsequently exhibit large gas mobility reduction. This experimental study, for the first time, confirms the ability of the two salt solutions reaction to generate nitrogen gas spontaneously upon contact under certain conditions. The generated gas is used to generate foams in the presence of a foaming agent. This newly proposed technique of foam generation could significantly impact many oil and gas operations including conformance control during EOR processes, fracturing, and acid stimulation operations.

Study on Enhanced Oil Recovery Using Microorganism Generating Foam in Presence of Nanobubbles

Both high cost and environmental load of surfactant are issues to be solved in foam EOR. Moreover, it is difficult to control the injection of surfactant and gas so that the foam is generated in only high permeable zones selectively in oil reservoir. The authors have found a foam generating microorganism and hit upon an idea of the microbial foam EOR which makes the microorganism do generating foam in oil reservoir. The mechanism of the microbial foam generation and culture condition suitable for the foam generation were studied in this study. A species of Pseudomonas aeruginosa was used as a foam producer in this study. It was cultured in the medium consisting of glucose and eight kinds of minerals at 30 °C and atmospheric pressure under anaerobic conditions. Because P. aeruginosa generally grows better under aerobic conditions, the microorganism was supplied with oxygen nanobubbles as the oxygen source. The carbon dioxide nanobubbles were also used as a comparison target in this study. The state of foam generation in the culture solution was observed during the cultivation. The surface tension, surfactant concentration, protein concentration, polysaccharides concentration and bacterial population of the culture solution were measured respectively. The foam was started to be generated by the microorganism after 2 days of cultivation and its volume became maximum after 3 days of cultivation. The foam generation was found in the culture solution which contained both oxygen nanobubbles and carbon dioxide nanobubbles whereas little foam was found in non-nanobubbles culture solution. The foam generation found in the culture solution containing carbon dioxide nanobubbles was more than that in the culture solution containing oxygen nanobubbles. Both gas and protein concentration increased along with the formation of the foam whereas surfactant and polysaccharides were not increased, therefore, the foam was assumed to be generated with gas and protein which were generated by P. aeruginosa. It was found that the carbon dioxide nanobubbles were positively charged in the culture medium whereas they were negatively charged in tap water through the measurement of zeta potential of nanobubbles, therefore, the carbon dioxide nanobubbles attracted cations in the culture medium and became positively charged. Positively charged carbon dioxide nanobubbles transported cations to the microbial cells of P. aeruginosa. Among cations in the culture medium, ferrous ions are essential for the protein generation of P. aeruginosa, therefore, the positively charged carbon dioxide nanobubbles attracted ferrous ions and transport them to the microbial cells, resulting the growth and metabolism of P. aeruginosa were activated. Those results suggest that the microbial foam EOR can be materialized by supplying the microorganism with carbon dioxide nanobubbles or ferrous ions.

Direct Visualization and Quantification of NCF-Strengthened CO2 Foam Generation, Propagation and Sweep in a 2D Heterogeneous Fracture Network Model

CO2 foam holds promising potential for conformance improvement and mobility reduction of CO2 injection in fractured systems. However, there still exists two main issues hampering its wide application and development, 1. Instability of CO2 foam lamellae under reservoir conditions, and 2. Uncertainties of foam flow in fracture systems. To address these two issues, we previously developed a series of functional nanocellulose materials to stabilize the CO2 foam (referred to NCF-st-CO2 foam), while the primary goal of this paper is to thoroughly elucidate foam generation, propagation and sweep of NCF-st-CO2 foam in fractured systems by using a self-designed visual heterogeneous fracture network. We found that NCF-st-CO2 foam produced noticeably greater pressure drop (ΔP) than CO2 foam during either co-injection (COI) or surfactant solution-alternating-gas (SAG) injection, and the threshold foam quality (fg*) was approximately 0.67. Foam generation was increased with total flow rate for CO2 foam and stayed constant for NCF-st-CO2 foam in fracture during COI. CO2 breakthrough occurred at high flow rates (>8 cm3/min). For SAG, large surfactant slug could prevent CO2 from early breakthrough and facilitate foaming in-situ. The increase in sweep efficiency by NCF-st-CO2 foam was observed near the producer for both COI and WAG, which was attributed to its better foaming capacity. Film division and behind mainly led to foam generation in the fracture model. Gravity segregation and override was insignificant during COI but became noticeable during SAG, which caused the sweep efficiency decreased by 3~9% at 1.0 fracture volume (FV) injected. Due to the enhanced foam film, the NCF-st-CO2 foam was able to mitigate gravitational effect, especially in the vicinity of producer.

Foam Generation in the Presence of Residual Oil in Porous Media

This paper studies the effect of trapped, emulsified oil on the requirement for the geometrical Roof snap-off for foam generation in a porous medium. We extend an existing hydrodynamic pore-level model to describe the liquid accumulation in an appropriately-sized pore in the presence of oil. The effect of oil is simulated by adjusting the pore shape to be asymmetrical as observed in microfluidic experiments with residual oil. We alter the boundary and initial conditions of the problem to test various scenarios. Specifically, four cases are presented. The liquid accumulation is presented when the amount of wetting liquid volume connected to the pore is altered through changing the boundary conditions (cases 1 and 2). Moreover, the effect of drier surrounding medium and/or drier pores is also tested by increasing either the capillary pressure surrounding the pore or the capillary pressure of the pore itself (cases 3 and 4). We find that the presence of residual oil affects the liquid accumulation times when there is no external liquid pressure gradient applied. Additionally, residual oil presence makes the Roof snap-off criterion for liquid accumulation stricter. To augment our pore-level study, we use a statistical pore network to observe the effect of the microscopic changes observed in our pore-level model macroscopically. Our results indicate that a stricter Roof snap-off criterion leads to fewer germination sites for lamellae generation. Our pore network analysis computes the generation rate constant to be as much as four times larger in the absence of oil than in its presence. Results suggest that changes to the shape of pore constrictions by emulsified oil reduce the effectiveness of foam generation.

Increasing the stability of the fire extinguishing foam by replenishing the liquid phase during sprinkling

Introduction. The destruction of foam films occurs when they reach critical thickness and lose the liquid phase as a result of syneresis and evaporation, which are rather difficult to slow down. We have proposed a method for increasing the stability of the fire extinguishing foam by means of replenishing the liquid phase through sprinkling.Methods. Foam stability was measured by the time of destruction of 25 % of the initial foam volume. The concentration of the foaming agent in the sprinkled solution varied from 0.5 to 6 %. Carboxymethylcellulose sodium salt (Na CMC) was used as a stabilizing additive. Field studies were carried out by feeding foam and solution from two AT-3,2-40 (43253)001-MS tank cars.Results and discussion. It has been established that the foam stability is influenced by the sprinkling intensity and the foaming agent concentration. Foam sprinkling with the solutions having low concentration of thefoaming agent leads to the washout of surfactants from the films that reduces the foam stability. The sprinkling intensity reduction boosts the foam stability due to the replenishment of the moisture lost through evaporation. The foam stability was maximal in case of sprinkling with a 2 % solution of the foaming agent, while the sprinkling intensity had no influence. An increase in the concentration of the foaming agent in the sprinkled solution led to a decrease in the foam stability. It is found that a smaller amount of the foaming agent is consumed to maintain the amount of foam through sprinkling than to replenish the destroyed amount through additional foam generation. It is shown that various stabilizing additives can be added to the foam in the process of sprinkling. If Na CMC is added to the solution exposed to sprinkling, the time of foam destruction goes up 3–5 times even in case of a non-recurrent sprinkling session. Field tests have confirmed the feasibility of adding stabilizing additives to the foam by means of sprinkling.Conclusions. The results of the research have shown the feasibility of co-feeding the foam and surfactant solutions, containing various stabilizing additives, in order to extinguish fires and generate stable foams.

Effects of Gravity on Foam Behavior in Roughened Model Fractures

Summary In this study, to investigate how gravity affects foam in open vertical fractures, we report foam experiments in three 1-m-long, 15-cm-wide glass-model fractures. Each fracture has a smooth wall and a roughened wall. Between the two walls is a slit-like channel representing a single geological fracture. Three model fractures (Models A, B, and C) share the same roughness and have different hydraulic apertures of 78, 98, and 128 µm, respectively. We conduct foam experiments by horizontal injection in the three model fractures placed horizontally and sideways (i.e., with the model fractures turned on their long side), and in Model A placed vertically with injection upward or downward. Direct imaging of the foam inside the model fracture is facilitated using a high-speed camera. We find that foam reaches local equilibrium (LE; where the rate of bubble generation equals that of bubble destruction) in horizontal-flow experiments in all three model fractures and in vertical-flow experiments in Model A. In fractures with a larger hydraulic aperture, foam is coarser because of less in-situ foam generation. In the vertical-flow experiments in Model A, we find that the properties of the foam are different in upward and downward flow. Compared with downward flooding, upward flooding creates a finer-texture foam, as sections near the inlet of this experiment are in a wetter state, which benefits in-situ foam generation. Moreover, less gas is trapped during upward flooding, as gravitational potential helps overcome the capillarity and moves bubbles upward. In the sideways-flow experiments, gravity segregation takes place. As a result, drier foam propagates along the top of the fractures and wetter foam along the bottom. The segregation is more significant in fractures with a larger hydraulic aperture. At foam quality 0.8, gas saturation is 27.7% greater at the top than the bottom for Model C, and 19.3% and 10.8% for Models B and A, respectively. Despite the gravity segregation in all three model fractures, water and gas are not completely segregated. All three model fractures thus represent a capillary transition zone, with greater segregation with increasing aperture. Our results suggest that the propagation of foam in vertical natural fractures meters tall and tens of meters long, with an aperture of hundreds of microns or greater, is problematic. Gravity segregation in foam would weaken its capacity in the field to maintain uniform flow and divert gas in a tall fracture over large distances.