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It is difficult to produce oil from diatomite due to unique rock properties such as low permeability, high porosity, fine laminations, and fractures. Steam injection is a promising enhanced oil recovery method for diatomite, but the generation and injection of steam may lead to large energy cost and, potentially, well failures. Injection of hot water instead of steam provides a means to decouple pressure and temperature while still achieving the benefits of thermal recovery. This study investigates and compares oil recoveries from fractured diatomite cores (1.5 ″, 3.5 ″, and 5 ″diameter) using hot water and steam. Both hot water and steam injection at 200 °C were applied under spontaneous and forced imbibition conditions. Cores from two different reservoirs (A and B) were used. The B reservoir oil and brine formation were adopted for all cases. Synthetic steam boiler feed was used to create hot water and steam. An X-ray CT scanner was used to visualize in-situ phases saturations and characterize the porosity/oil saturation distribution. Wettability alteration toward water-wet conditions was observed clearly at elevated temperature (200 °C) for all cores. The Amott index, Iw, for hot water and steam injection around 200 °C with reservoir A conditions were 0.41 (A#1) and 0.36 (A#2), respectively. The final oil recovery from A cores at 45 °C and 200 °C were 62- 64 % and 78- 82 % OOIP, respectively. The A reservoir whole core with 5 ″ diameter at 45 °C showed greater oil recovery from spontaneous imbibition than the 1.5 ″ diameter core. The Iw and final oil recovery from core A with both steam and hot water injection at 200 °C was nearly identical. With B core, the Iw increased from 0.28 (45 °C, water) to 0.34 (200 °C, steam). The Iw of B core was equal to 0.33 after both hot water injection and steam injection. The final oil recoveries of both hot water and steam at 200 °C showed 76 % and 80 % OOIP, respectively. Both in situ visualization and effluent analysis shows that rock dissolution and fines migrations contribute the evolution of fracture and pore networks within the core. Therefore, results suggest that hot water provides the benefits of thermal recovery, in some regards, while decoupling pressure and temperature.
It is difficult to produce oil from diatomite due to unique rock properties such as low permeability, high porosity, fine laminations, and fractures. Steam injection is a promising enhanced oil recovery method for diatomite, but the generation and injection of steam may lead to large energy cost and, potentially, well failures. Injection of hot water instead of steam provides a means to decouple pressure and temperature while still achieving the benefits of thermal recovery. This study investigates and compares oil recoveries from fractured diatomite cores (1.5 ″, 3.5 ″, and 5 ″diameter) using hot water and steam. Both hot water and steam injection at 200 °C were applied under spontaneous and forced imbibition conditions. Cores from two different reservoirs (A and B) were used. The B reservoir oil and brine formation were adopted for all cases. Synthetic steam boiler feed was used to create hot water and steam. An X-ray CT scanner was used to visualize in-situ phases saturations and characterize the porosity/oil saturation distribution. Wettability alteration toward water-wet conditions was observed clearly at elevated temperature (200 °C) for all cores. The Amott index, Iw, for hot water and steam injection around 200 °C with reservoir A conditions were 0.41 (A#1) and 0.36 (A#2), respectively. The final oil recovery from A cores at 45 °C and 200 °C were 62- 64 % and 78- 82 % OOIP, respectively. The A reservoir whole core with 5 ″ diameter at 45 °C showed greater oil recovery from spontaneous imbibition than the 1.5 ″ diameter core. The Iw and final oil recovery from core A with both steam and hot water injection at 200 °C was nearly identical. With B core, the Iw increased from 0.28 (45 °C, water) to 0.34 (200 °C, steam). The Iw of B core was equal to 0.33 after both hot water injection and steam injection. The final oil recoveries of both hot water and steam at 200 °C showed 76 % and 80 % OOIP, respectively. Both in situ visualization and effluent analysis shows that rock dissolution and fines migrations contribute the evolution of fracture and pore networks within the core. Therefore, results suggest that hot water provides the benefits of thermal recovery, in some regards, while decoupling pressure and temperature.
Diatomite oil reservoirs are unconventional. They hold billions of barrels of oil in a tight rock matrix with unusual physical properties, and contain a stress-sensitive natural fracture system that introduces a strong permeability anisotropy during fluid injection. Perhaps the most unusual feature of diatomite is geochemical in nature. Diatomite undergoes a silica-phase reordering and transformation as temperature is raised, whereby amorphous Opal-A is converted to a more ordered Opal-A' and more dense, crystalline Opal-CT. The injection of steam accelerates this naturally occurring process and leads to rapid densification and compaction and an irreversible loss of permeability. Nearly all of the field projects have been installed in Opal-A. Opal-CT is less permeable and this is the primary reason its development has been deferred. Although Opal-CT is less permeable under initial reservoir conditions, its stress and temperature-dependent compaction coefficients are much lower than those of Opal-A. As steam injection elevates reservoir temperature over time, the difference in permeability of Opal-A and Opal-CT is expected to narrow. It is chiefly for this reason that Opal-CT may hold more promise than currently supposed. The Opal-A field projects have demonstrated that closely spaced rows of wells are necessary for efficient oil recovery by water or steam injection. What is now called ultra-tight well spacing with rows of hydraulically fractured injectors and producers spaced only 35 to 45 feet apart was shown via numerical modeling more than 20 years ago to be necessary for maximizing oil recovery. That early modeling made use of laboratory determined rock and fluid properties and included the effects of thermally induced compaction. Following tuning of the early models using hydraulically fractured cyclic steam response, they were used to estimate ultimate recovery and thermal efficiency for steam injection into diatomite containing heavy oil. Given Opal-CT and ultra-tight well spacing, a combined cyclic steam and steamflood process was shown to be capable of ultimately recovering about 40% of the original oil-in-place, with a CSOR of 3 to 4 barrels of CWE steam per barrel of oil.
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