As technology advances in horizontal well drilling, long horizontals completion are now preferred for producers aiming to explore more oil-bearing zones, especially in heavy or tight oil reservoirs. However, for strong waterdrive horizontal wells, abrupt increase of water-oil ratio and abounding unwanted water production severely affect the profitability of the field due to the constant decrease of oil production and premature well shutting. The targeted reservoir of this work is a typical heavy oil reservoir with strong waterdrive. By December 2014, the average water cut for the two productive layers has increased 40-70%, for some wells especially, the water cut has exceeded 95% causing frequent well shutin. Therefore, to ensure the productivity of the horizontal wells, water shutoff has become a challenging and urgent task. According to the aquifer identification and water influx diagnosis, 27 horizontal wells distributed in aforementioned two productive layers were first categorized into two groups in order of treatment difficulties, after which foam-assisted gel and gel treatments were designed and conducted. For the three of the treated wells, the average water cut was significantly reduced from 80.3% to 48.0%. Although the gross liquid production rates were slightly reduced after treatment from 31.7 to 27.7 t/d, the oil production rate was considerably increased by 28.1 t/d. By January 2016, 4 500 t of the incremental oil was produced indicating the success of the water shutoff jobs. However, it should be noticed that the water cut of the N2 foam-assisted gel treated well started to rapidly rise after two months. This is probably caused by inappropriate foam/gel volume ratio. The water control strategies and field results in this heavy reservoir will provide the necessary clues for the design and application of water shutoff treatments for horizontal wells driven by strong water.

The SD107 gel system developed has good oil–water phase selective gelation and oil–water phase selective blocking properties. The static gel-forming experiment results showed that the gel water shutoff system formulated with oilfield reinjection water (oil content < 0.05%) has a viscosity of 200 mPa·s after gelation, and the gel water plugging system formulated with oilfield produced fluid (oil content ≥ 20.0%) had a viscosity of 26 mPa·s after gelation. Results of the core physical simulation experiment indicated that the enhanced recovery rate was the highest (34.6%) when the resistance ratio of the high-low permeability core was about 10.0 after plugging. As per the fluid volume (Q) of the oil well to be blocked, the maximum production pressure difference (∆P) was predicted, and on the basis of economic output, the resistance of the oil section, the resistance of the high water cut section, and the resistance of the water outlet section after plugging was used to calculate the plugging depth (re1, the limit water plugging radius), which offers a basis for the design of water plugging process parameters for horizontal wells. The field water plugging test results showed that after using this water plugging technology, the daily oil production increased from about 4 t/d to 20 t/d, the daily oil increase was 16 t/d, and the water cut decreased from 75% to about 25%. The water-blocking construction was a success.

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An organically crosslinked polymer with hydroquinone (HQ)–hexamethylenetetramine (HMTA) as crosslinker used for profile control was analyzed systematically at extremely high temperatures (over 150°C). The optimal gelation time and gelation performance may be achieved by changing the polymer and crosslinking agent concentrations. The gelation time is decreased and the gelation performance is improved as the concentration of polymer and hydroquinone‐HMTA increased. It still has a very dense microscopic three‐dimensional network structure after 3 months of aging at 150°C. The gel system can effectively improve the formation profile by plugging the high permeability layer and introducing subsequent water into the undisturbed layer.