Laboratory Evaluation of the Plugging Performance of an Inorganic Profile Control Agent for Thermal Oil Recovery

Abstract

During the process of steam thermal recovery of heavy oil, steam channeling seriously affects the production and ultimate recovery. In this study, fly ash was used as the plugging agent, and then a series of plugging experiments based on the results of two-dimensional (2D) experiments were conducted to study the effect of plugging the steam breakthrough channels. The experimental results show that the inorganic particle plugging agent made from the fly ash had a good suspension stability, consolidation strength, and injection performance. Because of these characteristics, it was migrated farther in the formation with a high permeability than in the formation with a low permeability, and the plugging rate was greater than 99%. After steam injection, it had a good anti-flush ability and stable plugging performance in the formation. In terms of the oil displacement effect, oil recovery in the formation with a low permeability was effectively improved because of plugging. The results show that the inorganic particle plugging agent could effectively control the steam channeling and it improved the development effect of the heavy oil reservoir.

1. Introduction

With the increasing demand for fossil energy, the development and utilization of heavy oil has attracted significant attention. Heavy oil is characterized by a high viscosity, high density, and high content of heavy components [1]. Thermal oil recovery is an effective method to develop heavy oil resources, including steam stimulation, steam flooding, in situ combustion, and steam assisted gravity flooding, of which steam stimulation and steam flooding are the most widely used [2,3,4]. However, steam channeling is the main problem regarding the steam thermal recovery of heavy oil owing to the heterogeneity of the formation and the difference of fluidity between the steam and heavy oil, which seriously affects the production and ultimate recovery of heavy oil [5]. The permeability is a key parameter to the fluid flow in porous media [6,7]. Therefore, it is crucial to weaken the negative impact of steam channeling.

Chemical plugging technology is an effective method to plug the steam breakthrough channels, which has the potential to greatly improve the development effect of heavy oil reservoirs [8]. At present, polymers, gels, particles, foams, resins, and microbials are widely used as plugging agents. Hu et al. [9] systematically investigated the EOR performance of foam flooding in different types of formations, and the results show that the flow resistance of the foam was promoted as the permeability increased. However, polymer gels, polymer microspheres, and expanded particles are not only expensive, but also cannot meet the technical requirements of the plugging strength needed in formations with a high permeability [10,11]. Foam plugging agents are limited by their thermal stability, and many low-temperature effective foam stabilizing agents cannot be used at high temperatures [12,13]. A short consolidation time and high cost limit the application of resin plugging agents [14]. The inorganic particle plugging agents are an ideal material owing to their high temperature and salt resistance, good stability, high compressive strength, and wide range of consolidation time adjustments [15,16].

Inorganic solid particles are mostly used as anti-channeling agents, such as cement and clay. The anti-channeling effect mostly depends on the particles’ physical blockage. Although an anti-channeling agent of this kind has a good temperature resistance, it cannot reach the depth of formation because of the inferior injection performance, short plugging distance, and continuous fingering phenomenon that occurs after the steam flooding. After a long duration of high temperature aging, the increasing pores in porous media may shorten the plugging validity. In addition, they may cause greater damage due to their non-selective plugging [17]. Cement was first applied to plug steam breakthrough channels, but its application was limited by the short consolidation time and inability to realize deep profile controlling [18].

Inorganic solid particles, including fly ash, oily sludge, and scum, can be made into plugging agents. The plugging agent is composed of inorganic ultrafine solid particles, retarder, an adhesive-enhancing agent, and a consolidation agent. These solid particles have a strong compatibility with the formation. Their application also solves environmental problems to a certain extent, so they are widely used to plug the steam breakthrough channels in heavy oil reservoirs [19]. Fly ash and slag are similar to cement, and are hydraulic cementitious materials with a potential activity [20]. The temperature and activator are necessary conditions for activating the fly ash and slag. By adjusting the temperature and dosage of the activator, the solidification time of the cementation materials, such as fly ash and slag, can be controlled [21]. The solidified mechanism of fly ash is similar to the cement solidification process. In an alkaline environment, the mineral forms a variety of hydrates with a crystal structure around the micro particles through a series of chemical reactions and ion exchange in various ways. Under the action of molecular forces, the colloidal particles composed of micro particles and hydrates condense into a network structure, and then dehydrate to form a semi-rigid plate material [22]. Pan et al. [23] used industrial slag as the main agent to prepare a high-temperature plugging agent. The experimental results show that the plugging agent could effectively plug the steam breakthrough channels, and could then expand the sweep coefficient of the injected steam.

Here, we considered the bad adaptability of the traditional plugging agent. In this study, a series of sand-pack experiments based on the results of two-dimensional experiments were conducted to study the plugging effect of inorganic particle plugging agents in the steam breakthrough channels. By reducing the phenomenon of steam channeling through plugging the layer with a high permeability, we could adjust the steam injection profile, increase the steam sweep coefficient, and increase the ultimate recovery of heavy oil.

2. Characteristics of Steam Channeling between Two Wells

The 2D experiment of the steam stimulation intuitively displayed the process of steam channeling in two wells, and the experimental model is shown in Figure 1, Figure 2 and Figure 3, namely the temperature distribution between the two wells during the steam stimulation, where the unit of temperature is °C. Figure 2 shows that the high temperature front of steam advanced along the layer with a high permeability, and the reservoir temperature gradually decreased with the increase in distance. With the increase in the stimulation cycles, the heating radius of the steam injection well increased, and the fluidity of the crude oil within the heating range increased. During the eighth steam stimulation, obvious steam channeling was formed between the two wells. Steam in the channeling layer had an ineffective flow, and the reservoir temperature and steam injection wellhead temperature exhibited little difference, as shown in Figure 3. Because there was positive rhythmic formation, the permeability difference between the upper and lower layers was 8.59, and the permeability of the lower layer was as high as 7.64 D. Steam easily passed through because of the low seepage resistance, so the phenomenon of steam channeling occurred in the lower layer during the process of steam stimulation.

It can be seen from the experimental results that steam is more likely to break through in the formation with a high permeability during the process of steam stimulation. Steam channeling leads to a decrease in the final recovery factor of heavy oil, greatly increases production cost, and seriously affects the development of heavy oil resources. Therefore, according to the results, a series of sand-pack experiments were conducted to study the adaptability of the inorganic particle plugging agent in steam breakthrough channels.

3. Experimental Section

3.1. Material

The oil samples were heavy oil from the Henan oilfield, and the viscosity of degassed crude oil at the reservoir temperature was 16,110–21,440 mPa∙s. The salinity of the formation water was 1792 mg/L. The inorganic particle plugging agent made in the laboratory was composed of the fly ash, a suspension agent, a consolidation agent, and an auxiliary agent. The mass concentration of fly ash in the plugging agent was 25%, and the chemical composition of the fly ash is shown in

Table 1. Composition and content of the fly ash.

SiO2(%)	Al2O3(%)	Fe2O3(%)	CaO(%)	MgO(%)	K2O(%)	Na2O(%)
55.63	18.38	6.75	4.93	1.72	2.49	1.09

. The sample of sand in the formation was used for filling the model of the sand-pack.

3.2. Experimental Setup

The one-dimensional experiment system is shown in Figure 4. It consisted of an injection module, main module, data acquisition module, and produced liquid collection module. The injection module was composed of the liquid injection subsystem. The steam injection subsystem was mainly composed of a high-pressure precision injection pump, intermediate piston vessel, air compressor, and steam generator. The main module was mainly composed of the sand-pack and high temperature electric heating sleeve. The working pressure was adjustable from 0 to 70 MPa, and the working temperature was adjustable from 0 °C to 200 °C. The data acquisition module consisted of the temperature and pressure sensor, differential pressure sensor, and control cabinet. The produced liquid collection module was composed of a receiving container, back pressure valve, and measuring instrument. The sand-pack was 100 cm long with an inner diameter of 3.8 cm, and there were six pressure monitoring points including the inlet, as shown in Figure 5. The basic data of the sand-packed models is shown in

Table 2. The basic data of the sand-packed models.

Model Number	Diameter (cm)	Length (cm)	Pore Volume (mL)	Porosity (%)	Permeability (D)
1	3.8	100	302	27.32	1.15
2	3.8	100	359	32.46	7.23
3	3.8	100	316	28.54	0.99
4	3.8	100	373	33.67	7.68
5	3.8	100	298	26.85	1.09
6	3.8	100	355	31.98	7.16

.

3.3. Experimental Procedure

In order to study the plugging performance of the inorganic particle plugging agent in the formation with a high permeability, effectively solve the phenomenon of steam channeling in the process of steam stimulation, and improve the ultimate recovery of heavy oil, this study conducted suspension stability and consolidation strength tests, sand-pack plugged experiments, and one-dimensional physical simulation oil displacement experiments. The specific experimental process is as follows:

• Suspension stability and consolidation strength test

The relative height sedimentation method was used for evaluating the performance of the inorganic particle plugging agent. After the inorganic particle plugging agent solution was stirred for 1 h, it was poured into a 25 mL centrifuge tube and placed in an oven at 80 °C for 6 h. The precipitation volume in the centrifuge tube was recorded over different stages. The change in plugging agent solution was observed for more than 6 h, including the initial set time, final set time, and consolidation process.

• Plugging experiment

First, the plugging experiment was conducted to confirm the depth that the inorganic particle agent reached in a formation. After 1 pore volume (PV) of the plugging agent was injected into models No. 1 and No. 2 at a speed of 1 mL/min, the inlet and outlet valves were closed and placed in an oven at 80 °C to solidify for 12 h. The models were flooded with water at a speed of 1 mL/min after cooled, and the pressures of each monitoring point were recorded by the data acquisition system. Then, the steam flooding was conducted to evaluate the scour resistance ability. Then, 10 PV of steam was injected separately into models No. 1 and No. 2, and the inlet and outlet pressure were recorded. Finally, the plugging experiment was conducted in the parallel model, which was composed of models No. 3 and No. 4. Under the same experimental conditions, 0.5 PV of the inorganic particle plugging agent was injected, and then 0.05 PV of water was injected at a speed of 1 mL/min. The water was injected into this model at a speed of 1 mL/min, and the inlet and outlet pressure were recorded.

• Oil displacement experiment

First, models No. 5 and No. 6 were saturated with oil, and the oil saturation of the models was calculated according to the volume of water production. Then, models No. 5 and No. 6 were connected in a parallel model, and steam was injected into this model until the water cut increased to 98%; meanwhile, the oil and liquid production were recorded. Then, 0.5 PV of the inorganic particle plugging agent was injected, and then 0.05 PV of water was injected at a speed of 1 mL/min. Finally, steam was injected into this model until the water cut increased to 98%; meanwhile, the oil and liquid production were recorded.

4. Experiment Results

4.1. Stability Evaluation

The main component of the inorganic particle plugging agent was fly ash, which was prepared by adding a suspension agent, consolidation agent, and auxiliary agent. The purpose of adding a suspension agent was to improve the suspension stability, and the role of the consolidation agent was to activate the fly ash and to generate hydration with the network structure; this hydration reaction rate was regulated by the auxiliary agent. The inorganic particle plugging agent solution was injected into the target formation in the form of a suspension, and its suspension stability, final set time, and consolidation strength were important indexes to evaluate the plugging effect. The smaller the volume of water separated from the inorganic particle plugging agent solution, the better the suspension performance. The final set time and consolidation strength were evaluated using the visual evaluation method. The consolidation time was determined by the strength of the inorganic particle plugging agent system.

As can be seen from Figure 6, with the increase in time, the precipitation volume of the plugging agent system in the centrifuge tube had an insignificant change. The precipitation volume decreased from 25 mL to 24.2 mL, with a change of 0.8 mL. After more than 4 h, the precipitated volume appeared to be stable, and the water extraction rate was 3.2%, indicating that the plugging agent solution had a good suspension stability.

Hydraulic compounds were generated from the plugging agent solution through some microscopic chemical reactions, and the reaction degree was macroscopically expressed as the strength change in the plugging agent.

Table 3. Consolidation time and consolidation strength.

Number	Time (h)	Appearance
1	3	Suspension, and high fluidity
2	6	Comparatively high fluidity, and beginning of consolidation
3	8	Medium fluidity, and unstable form
4	10	Stable form, and relatively high strength
5	11	Stable form, and high strength
6	12	Rigid strength, and the glass rod cannot enter
7	13	Rigid strength, and the glass rod cannot enter

shows that the initial setting time of the plugging agent solution was 6 h, with a relatively high fluidity. After 10 h, the formation of the plugging agent system was stable, and it had a relatively high strength. After more than 12 h, the plugging agent system had a rigid strength. The results show that the plugging agent solution had a good consolidation strength and could meet the requirements needed to plug larger pores.

4.2. Plugging Evaluation

The anti-channeling agent should not only have a strong temperature resistance, but it should also have an easy injection, in order to achieve plugging in the deep formation. Therefore, the plugging experiment was conducted to confirm the depth that the inorganic particle reached in the formation. Compared with the monitored pressure before the consolidation of the inorganic particle plugging agent, the plugging distance was determined by the changes in pressure at each monitoring point on the sand-pack model after solidification. Figure 7 and Figure 8 show the changes in pressure at each monitoring point on the sand-packed model with an initial permeability of 1.15 D and 7.23 D, respectively. Each point in the curve is the ratio of pressure during water injection to stable pressure before injecting the plugging agent.

As can be seen from Figure 7, with the increase in the injection amount, the pressure ratio increased in monitoring points 1 to 5. Before monitoring point 3, the pressure ratio rose rapidly in the initial stage, and the curve fluctuated sharply after reaching the highest point, and finally tended to be basically stable. This phenomenon indicated that inorganic particle plugging agent had a good injection ability and could enter the middle and deep position of the sand-packed model. The hydraulic compound increased the seepage resistance of the model and caused a change in pressure. The pressure ratio at measuring point 6 was a relatively smooth straight line, indicating that the plugging agent could not reach the point. According to the calculation formula of the plugging rate, the greater the pressure difference, the greater the flow resistance of the formation, indicating that the inorganic particle plugging agent had a higher consolidation strength in the formation. The pressure difference between monitoring points 2 and 3 was large, indicating that the main plugging section of model No. 1 was between them.

The difference between Figure 7 and Figure 8 is the initial permeability of the sand-packed model. Figure 8 shows the plugging effect of the inorganic particle plugging agent in the formation with a high permeability. With the increase in injection volume, the pressure ratio increased in monitoring points 1 to 5. The main reason for the rapid rise in the pressure ratio before monitoring point 4 was that a large number of hydraulic compounds were generated at this position, which increased the seepage resistance and the pressure. It also indicates that the inorganic particle plugging agent had reached this position. The pressure ratio at measuring point 6 was a relatively smooth straight line, but the pressure ratios were all greater than 1, indicating that a small amount of plugging agent had reached the point. The pressure difference between measuring points 4 and 5 was large, indicating that the main plugging section of model No. 2 was between them.

Comparing the results of the two models, it can be seen that the inorganic particle plugging agent had a good injection performance and plugging effect, and could reach the middle and deeper part of the formation before consolidation. Compared with the formation with a low permeability, the plugging agent migrated farther in the formation with a high permeability. The plugging rate was greater than 99% in models No. 1 and No. 2.

Figure 9 shows the change in the displacement differential pressure with the volume of steam injection after the plugging agent consolidation. With the increase in the injection volume, the displacement pressure difference of models No. 1 and No. 2 were relatively stable with a small fluctuation range. After a continuous steam injection of 10 PV, the pressure difference of model No. 1 remained at 12.9 MPa and model No. 2 remained at 3.8 MPa; this indicates that the solidified plugging agent exhibited good adsorption and retention in the formation, excellent scouring resistance, and a stable plugging performance.

4.3. Selective Plugging in Porous Media

As can be seen from Figure 10, the plugging rate of the inorganic particle plugging agent reached 99.18% for the formation with a high permeability, and only 10.1% for the formation with a low permeability. It can be seen that the plugging effect of the inorganic particle plugging agent had a selective plugging effect, the layer with a high permeability was effectively plugged, and a small amount of plugging agent entered the low permeability layer.

4.4. The Displacement Effect

Table 4. Experimental data of the oil displacement.

Model Number	Fractional Flow Rate (%)	Pre-Plug Recovery Factor (%)	Fractional Flow Rate after Plugging (%)	Recovery Factor after Plugging (%)	Enhanced Oil Recovery (%)
5	25.00	31.28	48.00	55.62	24.34
6	75.00	60.33	52.00	64.78	4.45

shows the experimental results of the oil displacement in the parallel model. The fractional flow rate of the sand-packed model (No. 5) with a low permeability increased by 23%, while that of the sand-packed model (No. 6) with a high permeability was effectively reduced. The recovery factor of models No. 5 and No. 6 was improved by 24.34% and 4.45%, respectively. It could be seen that the inorganic particle plugging agent could effectively plug the high permeability formation, adjust the steam injection profile, expand the scope of the steam sweep, and improve the final recovery of the heavy oil reservoir.

5. Conclusions

In this study, through the performance evaluation of the inorganic particle plugging agent and laboratory experiments, the following conclusions were obtained.

(1)

The inorganic particle plugging agent made from the fly ash had a good suspension stability and consolidation strength. The water extraction rate was 3.2%, the consolidation time was 12 h, and the consolidation strength was rigid. It met the requirements for plugging large pores.

(2)

The inorganic particle plugging agent made from the fly ash had a good injection performance and plugging effect. The plugging depth was longer in the high-permeability formation, the plugging rate was greater than 99%, and the scour resistance was strong. It had the characteristic of “plugging larger pores but not plugging small” and showed little damage to the low permeability formation.

(3)

The inorganic particle plugging agent made from the fly ash could effectively plug the steam breakthrough channels, which could improve the steam injection profile and the thermal recovery of the heavy oil reservoir.