Three-dimensional physical simulation experiment study on carbon dioxide and dissolver assisted horizontal well steam stimulation in super heavy oil reservoirs

Summary Steam-assisted gravity drainage (SAGD) and steam and gas push (SAGP) are used commercially to recover bitumen from oil sands, but for thin heavy-oil reservoirs, the recovery is lower because of larger heat losses through caprock and poorer oil mobility under reservoir conditions. A new enhanced-oil-recovery (EOR) method, expanding-solvent SAGP (ES-SAGP), is introduced to develop thin heavy-oil reservoirs. In ES-SAGP, noncondensate gas and vaporizable solvent are injected with steam into the steam chamber during SAGD. We used a 3D physical simulation scale to research the effectiveness of ES-SAGP and to analyze the propagation mechanisms of the steam chamber during ES-SAGP. Under the same experimental conditions, we conducted a contrast analysis between SAGP and ES-SAGP to study the expanding characteristics of the steam chamber, the sweep efficiency of the steam chamber, and the ultimate oil recovery. The experimental results show that the steam chamber gradually becomes an ellipse shape during SAGP. However, during ES-SAGP, noncondensate gas and a vaporizable solvent gather at the reservoir top to decrease heat losses, and oil viscosity near the condensate layer of the steam chamber is largely decreased by hot steam and by solvent, making the boundary of the steam chamber vertical and gradually a similar, rectangular shape. As in SAGD, during ES-SAGP, the expansion mechanism of the steam chamber can be divided into three stages: the ascent stage, the horizontal-expansion stage, and the descent stage. In the ascent stage, the time needed is shorter during ES-SAGP than during SAGP. However, the other two stages take more time during nitrogen, solvent, and steam injection to enlarge the cross-sectional area of the bottom of the steam chamber. For the conditions in our experiments, when the instantaneous oil/steam ratio is lower than 0.1, the corresponding oil recovery is 51.11%, which is 7.04% higher than in SAGP. Therefore, during ES-SAGP, not only is the volume of the steam chamber sharply enlarged, but the sweep efficiency and the ultimate oil recovery are also remarkably improved.

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A New High-Temperature Gel for Profile Control in Heavy Oil Reservoirs

Journal of Energy Resources Technology ◽

10.1115/1.4031706 ◽

2015 ◽

Vol 138 (2) ◽

Cited By ~ 13

Author(s):

Changjiu Wang ◽

Huiqing Liu ◽

Qiang Zheng ◽

Yongge Liu ◽

Xiaohu Dong ◽

...

Keyword(s):

High Temperature ◽

Oil Recovery ◽

Heavy Oil ◽

Three Dimensional ◽

Heat Stability ◽

Steam Injection ◽

Oil Reservoirs ◽

Steam Flooding ◽

Profile Control ◽

Heavy Oil Reservoirs

Controlling the phenomenon of steam channeling is a major challenge in enhancing oil recovery of heavy oil reservoirs developed by steam injection, and the profile control with gel is an effective method to solve this problem. The use of conventional gel in water flooding reservoirs also has poor heat stability, so this paper proposes a new high-temperature gel (HTG) plugging agent on the basis of a laboratory experimental investigation. The HTG is prepared with nonionic filler and unsaturated amide monomer (AM) by graft polymerization and crosslinking, and the optimal gel formula, which has strong gelling strength and controllable gelation time, is obtained by the optimization of the concentration of main agent, AM/FT ratio, crosslinker, and initiator. To test the adaptability of the new HTG to heavy oil reservoirs and the performance of plugging steam channeling path and enhancing oil recovery, performance evaluation experiments and three-dimensional steam flooding and gel profile control experiments are conducted. The performance evaluation experiments indicate that the HTG has strong salt resistance and heat stability and still maintains strong gelling strength after 72 hrs at 200 °C. The singular sand-pack flooding experiments suggest that the HTG has good injectability, which can ensure the on-site construction safety. Moreover, the HTG has a high plugging pressure and washing out resistance to the high-temperature steam after gel forming and keeps the plugging ratio above 99.8% when the following steam injected volume reaches 10 PV after gel breakthrough. The three-dimensional steam flooding and gel profile control experiments results show that the HTG has good plugging performance in the steam channeling path and effectively controls its expanding. This forces the following steam, which is the steam injected after the gelling of HTG in the model, to flow through the steam unswept area, which improves the steam injection profile. During the gel profile control period, the cumulative oil production increases by 294.4 ml and the oil recovery is enhanced by 8.4%. Thus, this new HTG has a good effect in improving the steam injection profile and enhancing oil recovery and can be used to control the steam channeling in heavy oil reservoirs.

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Scaling Criteria for Waterflooding and Immiscible CO2 Flooding in Heavy Oil Reservoirs

Journal of Energy Resources Technology ◽

10.1115/1.4035513 ◽

2017 ◽

Vol 139 (2) ◽

Cited By ~ 17

Author(s):

Deyue Zhou ◽

Daoyong Yang

Keyword(s):

Heavy Oil ◽

Three Dimensional ◽

Field Application ◽

Oil Reservoirs ◽

Viscous Force ◽

Co2 Flooding ◽

Vertical Wells ◽

Heavy Oil Reservoirs ◽

Displacement Model ◽

Good Agreement

Scaling criteria have been developed and validated to evaluate performance of waterflooding and immiscible CO2 flooding in heavy oil reservoirs by using a three-dimensional (3D) sandpacked displacement model. Experimentally, the 3D physical model consisting of a pair of horizontal wells together with five vertical wells is used to conduct waterflooding and immiscible CO2 flooding processes, respectively. Theoretically, mathematical formulae have been developed for waterflooding and immiscible CO2 flooding by performing dimensional and inspectional analyses. The scaling group of the gravitational force to viscous force is found to be negligible when scaling up a model to its prototype. The relaxed scaling criteria are validated by comparing the simulation results of a synthetic reservoir with experimental measurements and then extended for a field application. There also exists a reasonably good agreement between the laboratory measurements and the field application with the determined scaling criteria.

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