High-temperature and High-Salt resisting gel water packing-off method

[0024] Example 1: Indoor core plugging test

[0025] At 125℃, the modified tannin extract plugging agent main agent was used to plug the cemented quartz sand non-cracked cylindrical core and the cemented quartz sand cracked square core. The results are shown in Table 1 and Figure 4.

[0026] The water permeability of the core without cracks (K w ) Is 1870.95×10 -3 μm 2 , The plugging agent formula is: 10% GKJ + 3% HMTA + 1% NaOH. The sol injection balance pressure is 0.011MPa, and the resistance coefficient (F r ) Is 25. At a constant temperature of 125°C for 5 days, the core was displaced with formation water at a Darcy velocity of 0.879m/d, the breakthrough pressure was measured to be 0.44MPa/cm, and the residual resistance coefficient (F rr1 ) Is 24000, the core is almost completely blocked, and the permeability drops to 0.08×10 -3 μm 2. Continue constant temperature aging, the residual resistance coefficient after 28d (F rr2 ) Is 20000, indicating that the thermal stability of the plugging agent is high, and the plugging layer is not damaged.

[0027] The matrix permeability of the fractured core is 70×10 -3 μm 2 , 0.3cm thick coarse sand interlayer in the middle, the average water permeability measured after the formation water saturated fracture core is 9230×10 -3 μm 2. The plugging agent formula is: 10% GKJ + 3% HMTA + 1% NaOH + 1% phenol + 0.5% sodium orthosilicate. The purpose of adding phenol and sodium orthosilicate is to increase the gel strength and adjust the gel time for better Seal the cracks well. The equilibrium pressure of sol injection is 0.0047MPa, and the resistance coefficient (F r ) Is 16.2. After 5 days of constant temperature at 125℃, the breakthrough pressure measured is 0.048MPa/cm, and the residual resistance coefficient (F rr ) Is 7200, the cracks are effectively plugged, and the average permeability drops to 0.38×10 -3 μm 2, Which greatly reduces the seepage capacity of fractured cores.

[0028] Table 1 Sealing test results of GKJ gel on cemented quartz sand core at 125℃

[0029] Parameter

[0030] Example 2 Shixi Oilfield Carboniferous deep well bottom water plugging field test

[0031] On October 27, 2001, the Shixi Oilfield Carboniferous deep well bottom water plugging was carried out on site. The basic data of SH1104 well are shown in Table 2. As the production has been stable for nearly 3 years, the amount of underground movable oil may not be much. In view of the serious flooding of the well and the high water pressure that may cause the main agent of the plugging agent to not easily enter the water layer, a special plugging method of temporary plugging agent-modified tannin extract plugging agent main slug-cement sealing slug is adopted. Among them, the temporary plugging agent formula is: 0.6% polyacrylamide + 0.1% sodium dichromate + 0.3% anhydrous sodium sulfite; the modified tannin extract plugging agent formula is: 10% GKJ + 3% HMTA + 1% NaOH; sealing section The plug is: 20% cement + 4% soil removal + 0.15% sodium borate. It is hoped that the water flow channel can be blocked and the economic production period of the oil well can be extended.

[0032] Table 2 Basic data of Well SH1104

[0033] Parameter

[0034] In the construction, the casing pressure is released first, and it stops when the liquid is seen. Then connect the pipeline, test the pressure to 50MPa, and it is qualified if it does not puncture or leak. The injection process includes: ①Temporary plugging agent 20m 3 ②Isolation fluid (clear water) 15m 3 ③Shut in well for 1 hour for setting; ④Modified tannin extract plugging agent 100m 3 ⑤Cement sealing agent 13m 3 ⑥ Displacement fluid (clear water) 20m 3 (The oil pipe is injected 15m 3 , The casing is injected 5m 3 ). The injection speed is 0.3~0.6m 3 /min, and keep the squeeze injection pressure <52MPa, shut in and wait for setting 5 days before opening the well. Figure 5 It is the production dynamic monitoring result of SH1104 well before and after the plugging treatment. In more than three months after the plugging treatment, the average daily fluid production of the well dropped to 92t, the daily average oil production increased to 13.4t, and the daily average water cut dropped to 85%. Compared with before the water shutoff, the daily increase in crude oil production was 4-8t, and the water cut decreased by 6%-10%. However, from the production dynamic curve, the most obvious change was the daily liquid production. When the oil pressure remained basically unchanged (19±1MPa), the decrease gradually increased, from 105t before plugging to 81t after 3 months of plugging. And it is still showing a downward trend. The reason may be that the original Φ3.5mm nozzle was replaced with a Φ4.0mm nozzle for production when the well was reopened, resulting in a large initial fluid production, and later it was replaced with a Φ3.5mm nozzle. The liquid production volume is gradually decreasing.

[0035] The total cost of chemical agents and preparation for this pilot test is about 120,000 yuan. Based on calculations based on the water content of 90% from May to July in 2001, the daily production of 105 tons of fluid, and the daily production of 9 tons of oil, the plugging validity period is about 204 days. Cumulative reduction in liquid production was 3500t, and cumulative crude oil increase was 660.4t. Excluding the benefit of the reduction in liquid production, chemical agent input/net increase in crude oil output = 1/5.5.

[0036] Since Well SH1104 has been producing crude oil (60t/d) steadily for many years, the amount of underground movable oil is limited and the flooding time is long. The main plugging agent injection volume is only 100m 3 , According to the relationship between the amount of plugging agent (Q) and the theoretical plugging radius (R): Q=πR 2 hΦ (where h is the treatment layer thickness of 16m, Φ is the average porosity of 0.1322), and the calculated R is only 4.12m. This value may be too small for the SH1104 well with the high temperature bottom water cone, so that the water channel cannot be completely blocked. If the amount of chemical injection is appropriately increased during construction, better results may be achieved. Even so, the three-slug technology has made breakthrough progress for the first time in blocking the high temperature and high pressure bottom water of deep wells.