This paper presents the key aspects of nitrogen-assisted cyclic steam stimulation field trial at Post-CHOPS wells in FNE field, Sudan. FNE field is a heavy-oil asset with compositional gradient (13.87 to 18.1°API, in-situ viscosity of 226 to 255 cp) in massive unconsolidated sandstones at depths of 1,500 to 1,900 ft, with a permeability of 2 to 9 Darcies and strong bottom-water drive. Initially, cold heavy oil production with sand (CHOPS) was applied to exploit easy oil at upper zones of entire play. When flow rates of CHOPS wells declined to economic limits, or producers were too cool (reservoir temperature 111°F) to pump efficiently, nitrogen-assisted cyclic steam stimulation was to increase reservoir pressure, decrease heavy-oil viscosity, and boost well production. The specific technical points are highlighted below:

  1. In-house studies, including viscosity reduction test and numerical simulations, recommended that steam volume (cold-water equivalent) of 11,442 bbl per cycle based on 268 bbl/ft, with 70 to 75% quality, will be injected into the reservoir at rate of 1,260 bbl/d, nitrogen injection volume per cycle is 4.75 MMscf, soak time is for 5 to 7 days to allow the heat and pressure to distribute more uniform through the reservoir, then go to puff process. Pump is set 30-60 ft below the lowermost perforations to maximize fluids production through keeping fluid-level well below bottom perforations. By the end of pumping, bottomhole flowing pressure can declined to 70 psi. Steam and nitrogen injection sequence at updip wells is to inject steam first, followed by nitrogen injection. For downdip wells, nitrogen injection is the first and steam injection comes later to mitigate water influx.

  2. Re-completion strategy: squeeze cement into CHOPS producing zones because they contain wormholes, some communicating with aquifer, and perforate the lower pay interval to extract more viscous heavy oil.

  3. Failure risk assessment of production casings: pre-tensioning and full cementing of the casing with thermal cement is adopted in CHOPS wells for post-CHOPS thermal operation.

  4. Initial flowback flow rate is limited to less than the level of 500 bbl/d to reduce sanding risk and does not unduly de-pressure the formation at initial production.

  5. During pumping process, all fluids are exploited up the tubing string and the annulus is vented the flow-line. Pump works at optimal rate to ensure pressure drawdown less than critical drawdown threshold for sanding and water coning.

Field data confirmed that this trial is successful, with 2 to 3-fold production gain, relatively low water cut and no sanding issue. This technology is a useful option for post-CHOPS wells in the similar heavy-oil assets.

You can access this article if you purchase or spend a download.