HEAVY OIL PRODUCTION

Plugging agents add value to EOR operation

 Injection of fibrous material into a heavy oil reservoir plugged channels created by steam flooding and widened the sweep of oil-displacement chemicals. 

Pan Jingjun and Yang Jiangqiang, CNPC; Ren Biao and Ma Guozheng, Xinjiang Oilfield Co.

Adding chemical oil-displacement agents to steam flooding treatment has recently become a common Enhanced Oil Recovery (EOR) method. However, the significant reservoir heterogeneity in Xinjiang heavy oil reservoir has resulted in steam channeling, which may allow the injected chemicals to move to the producing well while bypassing the pay zone with high oil saturation. This has led to poor utilization efficiency and sweep efficiency of the chemicals. A new technique uses plugging agents to block the steam channels before injecting the oil-displacement chemicals. This helps to expand the sweep range of chemicals to the untouched area, improving recovery. After promising laboratory results were obtained, the method was applied to the 314 wells in regions 9(4) and 9(5) of Xinjiang field. Of these, 213 experienced increased oil production, totaling about 247,600 bbl (36,650 metric tons) over 7 yr, as well as an average reduction of more than 3% in watercut.

BACKGROUND

As steam flooding has become widely used in heavy oil reservoirs, some operators have supplemented the EOR technique by adding surfactants for oil displacement. In this auxiliary method, the chemical agents can be injected into the well either together with steam or before steam injection. Surfactants may reduce the oil-water interfacial tension and improve the rock surface wettability, thereby boosting oil-flushing efficiency. This may increase the effectiveness of steam flooding and ultimately improve EOR. In addition, surfactants may allow the crude oil to form emulsions, greatly reducing its apparent viscosity and thereby decreasing the flow resistance so the fluid is easier to lift out of the well.

Xinjiang heavy oil reservoir is in a field of severe heterogeneity. The reservoir was produced using many cycles of huff ’n’ puff before the commencement of steam flooding. This practice appears to have formed high-permeability zones, or steam channels, in the reservoir. These steam channels may act as short circuits for the oil-displacement chemicals, allowing some of them to move from the injection well to the production well while bypassing the zones with high oil saturation; this reduces the chemicals’ efficiency.

To solve this problem, a pilot operation was carried out using plugging agents-injected before the oil-displacement chemicals-to block the steam channels. It was hoped that this would eliminate the short circuit, allowing the injected surfactants to sweep easily through the untouched, oil-rich zones to improve the chemicals’ utilization efficiency and the oil-flushing efficiency, Fig. 1.

Fig. 1. The new EOR method involves plugging steam channels in the reservoir with fibrous material to force injected oil-displacement chemicals to sweep through untouched, oil-rich sections of the reservoir.

LABORATORY EXPERIMENTS

An initial set of laboratory experiments was conducted to evaluate the appropriateness of oil-displacement agents for injection into the pilot area. The experiments tested static and dynamic oil displacement, high-temperature resistance, emulsion viscosity reduction and core displacement for three displacement agents. A fibrous plugging agent was also tested for plugging capacity.

Emulsion viscosity reduction experiment. Viscosity of both the crude oil and the oil-water emulsion was measured using a Haake RS-150 rotational rheometer. Solution of 1% displacement agent #1 by volume in water was prepared; the solution was then mixed with sample heavy oil at oil-solution ratios of 8:2, 7:3, 6:4 and 5:5. Each sample was placed into the instrument’s beaker and stirred at the measuring temperature for 30 minutes; then the viscosity of the sample was recorded.

Initial results showed that the viscosity of heavy oil was reduced dramatically at oil-solution ratio of 8:2, and continued to decrease as the ratio approached 5:5, Table 1.

TABLE 1. Effect of various oil-solution ratios on emulsion viscosity

Another experiment measured the viscosity of the 7:3 oil-solution emulsion, and of unmixed heavy oil, at different temperatures, using oil from the pilot areas of Xinjiang field-regions 9(4) and 9(5)-and 1% solutions of displacement agents #1 and #2. Viscosity was tested at 10°C intervals from 20 to 70°C. The results showed that both the viscosity of heavy oil and that of emulsified heavy oil decrease appreciably as temperature increases, Table 2. Solutions of both displacement agents caused a large, roughly equivalent viscosity reduction that stayed relatively constant as temperature increased; the decrease was more than 90% for oil from region 9(4) and more than 98% for oil from region 9(5). The more pronounced viscosity reduction for emulsion of heavy oil from region 9(5) is predictable considering the higher viscosity of untreated heavy oil in that region compared with region 9(4).

TABLE 2. Viscosity of heavy oil and of 7:3 solution of oil and displacement-agent solution at different temperatures

Static oil-displacement experiment. Static oil-displacement ratio represents the capacity of the displacement agent to disperse the surface oil film of a sand grain. To test this capacity for the chemicals of interest, gas-flushed sands were mixed into heavy oil from the pilot areas at a heavy oil-sands ratio of 2:8 to form oil sand. Then, 10 gal of oil sand was placed into a tub, and oil-displacement agent was added. The tub was then placed into a water bath to soak at 60°C. When the oil sand and water reached static equilibrium, the volume of oil breakout from the oil sand was recorded.

The experiment was conducted for three oil-displacement agents plus a blank test without chemical added. The three surfactants yielded a static oil-displacement ratio that was more than twice the ratio of the blank test.

Dynamic oil-displacement experiment. An artificial core of silica sand was made in order to measure permeability. The core was saturated with heavy oil from regions 9(4) and 9(5). Then, the heavy oil was displaced using steam flooding alone and using steam flooding aided by displacement agent #1. For the samples from both regions, the use of chemical indicated an increase of more than 30% in oil production.

High-temperature resistance experiment. The adaptation of oil-displacement agents to steam flooding requires excellent resistance to high temperatures. This property is indicated by changes of surface tension and viscosity reduction after the chemical is exposed to high temperature. To test the high-temperature resistance of the three agents of interest, solutions of 1% agent by volume in water were prepared and placed into a closed pressure-resistant tank. After a maintenance time of 72 hr at 250°C, the surface tension of the solution was measured, as was the emulsion viscosity reduction ratio of a solution-heavy oil emulsion vs. the heavy oil alone at room temperature. The heavy oil tested was from region 9(4). Surface tension was measured using a ringmeter and an automatic surface tensiometer.

The results show that the surface tension and viscosity reduction ratio of the displacement agents change little with exposure to high temperature, making them excellent candidates for use with steam flooding, Table 3.

TABLE 3. High-temperature resistance of oil-displacement agents

Plugging agent test

High-temperature-resistant fibrous material was selected as the plugging agent, taking care that the material could be suspended in and carried by the displacement chemicals. The plugging strength was tested by injecting the plugging agent into an artificial core composed of sand, then measuring the break pressure of steam at constant 250°C after a maintenance time of 35 hr. The plugging agent was found to have a break pressure of about 4.4 MPa and excellent washout resistance.

FIELD APPLICATION

Field tests were conducted from 2000 to 2006 on 314 wells in 54 well groups of regions 9(4) and 9(5) in the Qi Guzu reservoir. In pilot region 9(4), the depth of the intermediate reservoir is 755 ft (230 m) and average net pay thickness is 49.2 ft (15.0 m). The original formation pressure is 2.5 MPa and original temperature is 18.7°C, with average porosity of 29% and oil saturation of 72%. The average density and the average viscosity of the heavy oil are 0.935 g/cm³ and 15,000 cP at 20°C, respectively.

In region 9(5), the depth of the intermediate reservoir is 886 ft (270 m) and average net pay thickness is 41.3 ft (12.6 m). The original formation pressure is 2.95 MPa and original temperature is 18.7°C. Average porosity is 29% and oil saturation is 70%. The average density and the average viscosity of the heavy oil are 0.931 g/cm³ and 6,615 cP at 20°C, respectively.

The 54 pilot groups comprise 314 wells in an inverted nine-spot pattern with well spacing of 230 ft (70 m). Liquid production from the pilot wells ranges between 126 and 315 bpd (20-50 m³/d). The wells produce 19-31 bopd (3-5 m³/d).

Before steam injection, 94-126 bbl (15-20 m³) of plugging agent was injected into each well, followed by 189-252 bbl (30-40 m³) of a 5-6% solution of displacement agent #1. A small amount of water was then injected to drive the chemical agents from the tubing into the formation. Fluid was pumped into the well at 2.5 bbl/min. (0.4 m³/min.); water was injected at less than 5 MPa. Steam injection was then conducted on each well. Cumulatively, 5,710 bbl (908 m³) of plugging agent and 12,060 bbl (1,918 m³) of displacement chemical were injected during the operation.

RESULTS

The field operation resulted in both increased oil production and reduced watercut, Table 4. Oil production was increased about 4,580 bbl (678 mt) per well group, for a cumulative increase of 247,600 bbl (36,650 mt). At the same time, water production stayed essentially flat.

TABLE 4. Production from pilot wells before and after application of plugging agents Click table to enlarge

On a per-well basis, average oil production rose to 13.5 bpd (2.0 mt/d) from 6.28 bpd (0.93 mt/d); average watercut fell to 81.5% from 84.5%. The average oil production growth per well was 790 bbl (117 mt).

For example, well group 95089 experienced a significant watercut reduction, and oil production increased to a range of 34-68 bpd (5-10 mt/d) from a previous average of about 27 bpd (4 mt/d). Well group 94121 also saw reduced watercut after stimulation, and oil production grew to an average of 47 bpd (7 mt/d) from an average of 20 bpd (3 mt/d). Three out of the 10 groups to which plugging and displacement agents were applied in 2006 achieved oil production growth of more than 2,000 bbl (300 mt); another five groups achieved increases of more than 680 bbl (100 mt).

Improvement in the sweep of steam flooding and displacement agents is indicated by the large number of wells that delivered EOR after treatment: 213 of 314 total production wells, or 68%, saw improved oil production.

Injection and production profiles. It was expected that successful plugging of the steam channels would result in a shift of both injection and production profiles to deeper in the reservoir, where more hydrocarbons were present. To test for such a shift, measurement was carried out to obtain the steam injection profile of injection well 94081 before and after plugging agents were applied in July 2001, Fig. 2. The results show that steam injection mainly occurred at the upper intervals of the well before application. After application, the steam injection profile was greatly improved by a shift of injection from high in the well to the lower intervals. On the production side, the liquid production profile of production well 95120 was obtained before and after the application of plugging agents. Similar to the injection profile, the results show a steep shift in liquid production to the lower, more oil-rich, intervals of the well from the higher intervals, Fig. 3.

Fig. 2. Comparison of injection profiles before and after application of plugging agents for injection well 94081 shows a shift toward injection lower in the well.

Fig. 3. Liquid production at well 95120 came from lower in the well after application of plugging agents compared with production before application.

Temperature profile. Measurement was also carried out to test the wellhead temperature of producing wells in region 9(5) before and after application of plugging agents in 2003. Liquid production temperature was shown to drop dramatically after stimulation, Fig. 4. This temperature drop indicates that steam channels in the reservoir were effectively plugged, enlarging the areal sweep of steam flooding and oil displacement chemicals.

Fig. 4. Liquid production temperature in region 9(5) decreased following application of plugging agents, indicating a greater areal sweep of steam flooding and oil-displacement chemicals.

CONCLUSION

The addition of plugging agents to reservoir stimulation using steam flooding and oil-displacement chemicals resulted in significant increases in oil recovery and watercut reductions in regions 9(4) and 9(5) of Xinjiang heavy oil reservoir. Before the use of plugging agents, steam channels had provided a short circuit from the injection well to production wells, allowing oil displacement chemicals to bypass oil-rich regions in the reservoir. The changes in water and oil production and other indicators suggest that the new method was effective in blocking these steam channels, forcing the chemicals to sweep through a larger area of the reservoir.

The results of this stimulation program indicate that plugging agents may become a valuable supplement to EOR methods in heavy oil reservoirs, especially in heterogeneous reservoirs.