High Pressure / High Temperature

Wettability alteration used for water block prevention in high-temperature gas wells

 A chemical system alters the formation wettability to intermediate gas-wet conditions, thereby decreasing capillary forces and enhancing clean-up of trapped water at low drawdown pressures. 

Mohan K.R. Panga, Yean Sang Ooi, Keng Seng Chan, Philippe Enkababian and Mathew Samuel, Schlumberger Well Services; Pei Ling Koh, Universiti Teknologi Petronas; and Pascal Chenevi�re, Total

Water accumulation near the wellbore or fracture face can decrease the relative permeability of oil and gas.^1–5 This restriction to oil and gas flow, due to increased water saturation, is called water block. Sources for excess formation water could be water-based fluids used in drilling, completion, matrix or fracture treatments; cross-flow of water to dry gas zones; or water imbibition into tight zones.⁶ The excess water is trapped in the formation, due to high capillary pressure in porous rock and viscous fingering of gas through water. The presence of clays, migrating fines, reservoir heterogeneity and other forms of formation damage, such as wettability alterations, can increase the severity of trapping.¹

Laboratory studies by Kamath and Laroche⁷, and Mahadevan and Sharma,^8,9 have shown that removal of water from the formation occurs in two stages—an initial displacement stage where water is expelled from the core, followed by a long-term evaporation stage. The amount of water displaced in the initial stage depends on the drawdown and the capillary pressure. In formations with high capillary pressure and low drawdown, a high water saturation is left in the formation after gas breakthrough, creating a water block. A long time is required in this situation to recover gas production by evaporation of the liquid. For drawdowns greater than capillary pressure, water is not a problem.^4,10

The slow clean-up of water blocks by evaporation can be enhanced by addition of volatile solvents. Successful cases have been reported in literature, where solvents have been used to clean up water and condensate blocks.^1,2,11–13 However, solvent-based clean-up is temporary, as the well has to be retreated with solvents if a water block reoccurs. Evaporation of water in the formation can also decrease permeability, due to brine precipitation. Zuluaga et al.¹⁴ have reported a 15–30% loss in absolute permeability due to precipitation.

An alternate method to enhance water removal is to increase the volume displaced in the initial stage by decreasing formation capillary pressure. The reduction of capillary pressure to very low values allows for water block clean-up, even at low drawdowns. Capillary pressure can be decreased by altering the wettability, decreasing the interfacial tension or by increasing the formation permeability (or pore radius).

Penny et al.⁵ used a non-water wetting agent during fracturing to reduce capillary pressure and enhance load water recovery. Their lab and field data show significantly improved water recovery after treatment. Li and Firoozabadi,¹⁵ and Tang and Firoozabadi^16–17 have used fluorochemicals to reduce capillary pressure by altering formation wettability from liquid wet to intermediate gas wetting state. Their results show good wettability alteration, but the chemicals are limited to a maximum temperature of 90°C. Fahes and Firoozabadi¹⁸ reported a different 3M-manufactured fluorochemical that shows good wettability alteration at high temperatures (140°C). Gas flood experiments showing water block clean-up after wettability alteration are yet to be published.

An experimental study was conducted to evaluate the feasibility of a preventive chemical treatment to avoid water block formation. Unlike solvent-based methods that are temporary, the aim was to induce a long-term wettability change that reduces capillary pressure near the wellbore or the fracture face. Different classes of surfactants and polymers were tested for this purpose.

MATERIALS/METHODS

Using a chemical treatment to induce wettability change for water block prevention requires consideration of several factors. These factors include:

• The chemical must be stable at downhole conditions for a longer period of time.

• Since water blocks are more frequent in tight zones, permeability places a restriction on the chemical types that can be injected. The chemical’s molecular size must be small enough to avoid filtration at the formation face.

• The reduction in permeability due to chemical treatment must be minimized. Excessive damage can lead to an undesired increase in capillary pressure, which can reduce treatment efficiency.4

• The chemical’s adsorption and desorption characteristics must be conducive for long-term wettability change.

Three types of tests were conducted in this study to evaluate chemical performance with respect to the above-mentioned factors. First, contact angle tests were performed to select chemicals that show good wettability alteration from water-wet to intermediate gas-wet conditions. Second, the core samples were treated at 25°C and 126°C with the chemicals selected in the first stage. Damage caused by the treatment was analyzed, based on the porosity and permeability measurements. Brine-air imbibition tests on untreated and treated core samples were used to assess the wettability alteration by the chemical (or reduction in capillary pressure). Flushing with brine and ageing in brine at high temperatures were done to study desorption of the chemical, as well as its stability at high temperatures. Finally, a core slow test was conducted to check the improvement in clean-up of water blocks before and after treatment with the chemical selected from the second stage.

Five chemicals, A1-A5, were selected from 30 different chemicals after observing the contact angle produced when a drop of water is placed on a treated core. The core was strongly water-wet (contact angle is zero) before treatment. After treatment with chemicals A1–A5, the contact angle was greater than 90°, showing that wettability was altered to intermediate gas wetting conditions. Chemicals A1–A3 are surfactant-based, A4 is a fluoropolymer and A5 is a fluorotelomer.

IMBIBITION EXPERIMENTS & RESULTS

Brine-air imbibition tests were conducted on Ohio, Bandera and Berea cores. The mineral composition of these cores is shown in Table 1. After trimming the cores to required dimensions (Table 2), porosity and gas permeability of the dry cores were measured. Porosity values are typically in the range of 18–21%, and gas permeability values are in the range of 0.5–2.0 mD for Ohio cores, 30–60 mD for Bandera cores and 70–175 mD for Berea cores.

TABLE 1. Mineral composition of cores

Imbibition experimentation on dry cores was conducted by placing the core in a graduated cylinder containing 2-wt% KCl brine, so that only the bottom of the core touches the brine. The brine volume that imbibes into the core, due to capillary suction, was calculated from the change in weight on the balance. The evaporation effect was minimized by choosing a cylinder with a narrow diameter and by covering it with a lid. A blank experiment was also conducted, along with an imbibition test to correct for evaporation. From this experiment, the evaporation rate was found to be between 0.0001–0.0002 gm/min. For the experiments reported here, maximum error due to evaporation was ± 3%.

After the initial imbibition test, the core was treated with the chemical by pumping the solution through the core and shutting it in an oven at 25°C or 126°C. For the chemicals tested in this study, no injectivity problems were observed in the low-permeability Ohio cores, as long as the chemicals were diluted in compatible solvents. The chemical concentration used to treat the core is shown in Table 2. Depending on the chemical system, shut-in times varied from 3–12 hr. After shut-in, the cores were flushed with gas to remove the liquid containing the unadsorbed chemical, and consequently dried in the oven at shut-in temperature.

TABLE 2. Core properties before and after treatment and chemical concentrations

The porosity and permeability of the dry treated cores was measured to estimate the damage due to chemical treatment. Imbibition tests were repeated to compare the intake rate of brine before and after the treatment. If the wettability is altered to intermediate gas-wet conditions, then the imbibition rate of brine should decrease, due to reduction in capillary pressure. After imbibition, 15–20 pore volumes of brine were flushed through the core, and the imbibition test was repeated to check for desorption of the chemical and loss in wettability alteration.

The brine imbibition data of untreated Ohio (2mD), Bandera (40mD) and Berea cores (153mD) of equal dimensions are shown in Fig. 1. The amount of brine imbibed is expressed as the percentage of water saturation (S_w) inside the core as a function of time. The plot shows that the imbibition rate is slow in low-permeability Ohio core, compared to high-permeability Berea core. These imbibition dynamics were explained earlier, showing that the imbibition rate is proportional to the square root of permeability.¹⁶ The final saturation of brine, however, is high in low-permeability core, due to strong capillary forces.

Fig. 1. Brine saturation in Ohio, Bandera and Berea cores as a function of time. Core dimensions used in tests are L = 4.5 cm and D = 2.54 cm. .

Table 2 shows the core properties before and after treatment. Cores 1, 2 and 3 were treated with a solution containing 5% A1, 50% Isopropanol (IPA) and 45% brine (2wt% KCl). The shut-in temperature was 25°C for cores 1 and 2, and 126°C for core 3. The shut-in time was 12 hr. Figures 2(a)–(c) show the brine imbibition data of cores 1–3 before and after treatment, and after flushing brine through the core. The treatment reduced the imbibition rate in all three cores, showing that wettability is altered to intermediate gas wetting conditions. Flushing the core with 15 PV of brine further reduced the imbibition rate of brine.

Fig. 2. (a) Core 1 (b) Core 2 (c) Core 3. Imbibition data of cores 1-3 show that flushing makes the core more intermediate gas-wet. .

This reduction in imbibition rate could be due to a high concentration of surfactant used for treating the core. At concentrations greater than critical micellar concentration (cmc), the surfactant has a tendency to form bilayers.¹⁹ While conclusive evidence is not available, by examining the data of other surfactants that belong to the same class as chemical A1, we believe that improved wettability alteration after flushing is due to the transition from bilayer to monolayer. In a monolayer, the surfactant’s hydrophobic tail is aligned toward the liquid, increasing the water repellency of the rock surface and making it non-water wet.

Such an effect can explain the improvement in wettability alteration after flushing. The final brine saturation after treatment in cores 2 and 3 is higher than the untreated cores. In core 2, this effect is more pronounced. This is due to increased capillary pressure caused by a reduction in permeability after treatment.4 The treatment reduced initial gas permeability by 8% in core 1, 36% in core 2 and 13% in core 3. The increase in capillary pressure due to excessive damage in core 2 outweighs the capillary pressure reduction, due to wettability alteration leading to an increase in final brine saturation.

Figures 3(a) and 3(b) show the imbibition results of cores 4 and 5, treated with a solution of 5% A2, 50% IPA and 45% brine. The cores were shut-in for 12 hr at 25°C. After treatment, both the cores show a reduction in imbibition rate due to wettability alteration. However, flushing with brine increased the imbibition rate in core 5 significantly, indicating desorption of the surfactant into brine. The imbibition results of core 5, after soaking in brine at 126°C for 2 days, show further reduction in treatment efficiency. The quick desorption, along with instability at high temperature, make A2 unsuitable for preventive treatments. Figures 4(a) and 4(b) show the imbibition results of cores 6 and 7 treated with chemical A3. The treatment reduced the imbibition rate in core 6, but the rate in core 7 is relatively unaffected. The increase in final brine saturation in the imbibition test, after soaking at a high temperature, shows that chemical A3 is not stable at high temperatures.

Fig. 3. (a) Core 4 (b) Core 5. Treatment with chemical A2 reduces the imbibition rate in cores 4 and 5. The treatment�s efficiency is lost after brine flush and soaking at high temperature. .

Fig. 4. (a) Core 6, (b) Core 7. Imbibition data of cores treated with chemical A3. The chemical is not stable at high temperatures. .

Figure 5 shows the imbibition data of core 8 treated with A4 diluted in an alcohol-brine mixture containing 2% A4, 50% IPA and 48% brine. The core is shut-in for 12 hr at 126°C. The imbibition rate of brine reduced considerably after treatment, indicating a decrease in capillary pressure and good wettability alteration to intermediate gas wetting conditions. Flushing the core with 15PV of brine did not affect the imbibition characteristics, showing that desorption of A4 into brine is negligible. However, the treatment reduced the core’s permeability by 45%, from 121mD to 67mD. When the above-mentioned A4 solution was injected into low and medium-permeability cores, a large amount of the chemical filtered out at the face of the core.

Fig. 5. Treatment with A4 changes the wettability to intermediate gas-wet conditions. The final saturation and the imbibition rate are significantly reduced after treatment. .

Upon careful observation, it was found that the tiny white precipitates on the core were from the A4 solution containing alcohol and brine. It was also observed that in solutions containing high brine concentration (4wt%), A4 is incompatible and precipitates out of the solution. The reason for 45% damage in core 8 was also thought to be the incompatibility of A4 with the treatment solution. After performing several fluid compatibility experiments, it was found that A4 is compatible in alcohol, or mixtures of alcohol and mutual solvent.

Filtration in low-permeability cores was not observed after diluting A4 in an alcohol-mutual solvent mixture. Figure 6 (a) shows the imbibition data of core 9 treated with a solution of 2% A4, 90% ethanol and 8% mutual solvent. The data show a reduction in imbibition rate after treatment with A4. However, the core’s permeability reduced from 174 mD to 85mD (51% damage), even after diluting A4 in a compatible solvent. To examine if the permeability damage was due to a high concentration of A4, core 10 was treated with 0.5% A4. The decrease in permeability after treatment was still around 50%. Figure 6 (b) shows the imbibition data of core 10. When compared to cores 8 and 9 treated with 2% A4, the treatment efficiency was low when the A4 concentration was reduced to 0.5%. Because of the chemical’s damaging nature, A4 was not tested further, though it showed good wettability alteration.

Fig. 6. Imbibition data of cores 9 (left) and 10 (right) treated with 2% and 0.5% A4 formulated in a mixture containing alcohol and mutual solvent. .

Cores 11, 12 and 13 were treated with a solution of chemical A5 prepared by diluting A5 in 2wt% KCl brine. Figures 7(a), (b) and (c) show the imbibition data of cores 11, 12 and 13, respectively. Core 11 was a low-permeability core treated with 8% A5 and shut-in at 126°C for 3 hours. The imbibition rate decreased significantly after treatment, and flushing with 15PV of brine did not affect the results. The final brine saturation in imbibition tests reduced from 95% before treatment to 10% after treatment (after 10 hr of imbibition).

Fig. 7. (a) Core 11 (b) Core 12 (c) Core 13. Treatment with A5 shows good wettability alteration to intermediate gas wetting in cores 11, 12 and 13. The permeability damage is lower than cores treated with A4. .

Cores 12 and 13 (medium and high permeability) were treated with 5% A5. The imbibition data show that the treatment reduced the final brine saturations to 15% and 23% in cores 12 and 13, respectively. These saturations were significantly lower than the saturations before treatment, which were 66% for core 12 and 63% for core 13. The reduction in permeability after treatment with the chemical was 20%, 12% and 9% for low-,
medium- and high-permeability cores, respectively. The A5 chemical showed the best performance among chemicals tested in this study. In the next section, gas flood experiments conducted to study water block removal before and after treatment with A5 are discussed.

GAS FLOOD EXPERIMENTS

A gas flood experiment was conducted to check wettability alteration’s effect on water block cleanup. It was expected that a reduction in capillary pressure, because of wettability alteration to an intermediate gas-wet state, would increase the volume of brine displaced by gas. The core’s dimensions and porosity were measured prior to core flow test. The core was loaded into a Hassler-type core holder, and a confining pressure of 1,000 psi was applied. The tests were conducted at 260°F, and a backpressure of 100 psi was applied to minimize evaporation at high temperatures.

A mass flow controller was placed upstream of the core to measure gas flowrate. The core’s gas permeability was calculated from the pressure drop across the core and mean gas flowrate in the core using Darcy’s law. The core was then saturated with 2% KCl by injecting brine at a constant rate of 2.5 ml/min. until residual gas saturation was reached. Gas was injected into the core at a constant pressure, and the amount of brine displaced out of the core was measured by weighing the fluid expelled at the exit. Due to the dead volumes present in the system, the core’s brine saturation could not be accurately calculated from the mass of fluid at the exit.

However, care was taken to conduct the displacement tests under identical conditions by flushing large volumes of brine before gas displacement stage, which ensured complete saturation of the core and the connecting lines with brine. Figure 8 shows an example of the displacement of brine from fully brine-saturated, low-permeability core (1.5 mD) when gas was injected at two different pressure gradients, 80 psi/ft and 472 psi/ft. The plot shows the mass of brine measured at the exit as a function of time during the gas displacement cycle. The brine was continuously displaced from the core until the gas broke through the core. After breakthrough, the amount of brine displaced was negligible, and clean-up was due mainly to evaporation. From the figure, it can be seen that the displacement rate was very slow at low-pressure gradients. The amount of brine cleaned up was also lower at 80 psi/ft.

Fig. 8. Brine displacement by gas in a low-permeability core (1.5 mD) at different pressure gradients. .

Figure 9(a) shows the results of water block clean-up during the displacement stage before and after treatment with chemical A5 in a low-permeability core (1.23 mD). The initial core clean-up prior to the treatment was conducted at a low-pressure gradient of 72 psi/ft (around 18 psi differential pressure across the 3-in. core). Then, the pressure gradient was increased further to 160 psi/ft, 240 psi/ft, 310 psi/ft and 380 psi/ft, respectively, at varied time intervals. Figure 9(b) shows the pressure gradients applied at different time intervals. The weight of brine displaced was measured, using the balance until gas breakthrough.

Fig. 9. (a) Water block clean-up from a brine-saturated core by displacement with gas at different pressure gradients before and after treatment with chemical A5. (b) Pressure gradients applied at different time intervals. .

The core was then treated with a solution containing 2% A5 + 10% ethanol + 88% brine, by injecting the solution at a constant rate of 2.5 ml/min in the injection direction, followed by a shut-in for 3 hr. After shut-in, the core was flushed with gas in the production direction to remove the unadsorbed chemical from the core. The core was again saturated with brine, and the gas clean-up cycle was repeated, as described in the before-treatment stage. The same pressure gradients and time intervals were applied during the brine clean-up with gas. To study the A5 chemical’s stability at high temperature and loss in efficiency due to desorption, 215 PV of brine were injected, and a second cycle of clean-up after treatment was performed.

The clean up results showed that the brine volume displaced was higher after treatment, and also after a long brine flush, when compared to the volume displaced before treatment (Fig. 9(a), Table 3). Before treatment, 17ml of brine were displaced from the system, whereas after treatment and after flushing with 215 PV of brine, the volumes displaced were 23ml and 28ml, respectively. The rate displacement was very low at 72 psi/ft before treatment, and flow was initiated only at 160 psi/ft. After treatment, the flow was initiated at 72 psi/ft. The results show that the fluid was mobilized at lower pressure gradients, due to wettability alteration with A5 to intermediate gas-wet conditions.

TABLE 3. Brine displaced by gas before and after treatment with chemical A5

DISCUSSION/CONCLUSIONS

An experimental study was conducted to evaluate the feasibility of water block prevention in gas wells by chemical treatment. The treatment aimed to reduce formation capillary pressure near the wellbore, or the fracture face, for a long period of time by altering wettability to intermediate gas-wet conditions. Three types of experiments—contact angle, imbibition and core flow tests—were conducted to test the wettability alteration produced by the chemicals, the stability of the chemicals at high temperatures, and desorption and longevity of the treatment. One of the main concerns in such treatments is the formation damage caused by chemical treatment that can increase capillary pressure, thereby reducing treatment effectiveness.

Five different chemical systems, A1–A5, were tested for applicability. The chemicals A1–A3 show wettability alteration at room temperature but are not stable at high temperatures for a long period of time. The chemical A4 shows good wettability alteration in high-permeability cores, but it causes significant damage (around 50%) to absolute core permeability. Imbibition data of low-, medium- and high-permeability cores treated with chemical A5 show excellent wettability alteration to intermediate gas wetting state. The damage caused by this chemical is considerably lower.  

ACKNOWLEDGEMENT

 The authors would like to thank Schlumberger and Total for granting permission to publish this article.

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