Water shutoff in mature reservoirs is traditionally achieved with cross-linked gels. By blocking the areas already swept by water, subsequently injected water can sweep an unswept area of the reservoir and thereby increase the oil recovery. However, it is a complicated process and the performance of polymer gel flood in complex reservoirs requires an accurate model that represents the reservoir features, chemical properties, and displacement mechanisms.
This paper presents a successful investigation of polymer gel behavior from laboratory to full field scales. First, a series of laboratory experiments were conducted to achieve a deep understanding of polymer gel behavior. The results show that the polymer viscosity, gelation time, and gel strength strongly depend on reservoir temperature, polymer type, polymer concentration, cross-linker concentration, pH and salt concentration, which are the successful keys of a polymer conformance control process. The optimal values of these parameters are proposed for applying in a pilot test. A series of numerical simulations are performed to history match with experiment data and generate parameters for field scale simulation. The adsorption phenomenon is fully integrated into the reservoir model for controlling and reducing this effect during the polymer flooding process.
According to the laboratory results, polymer gel flooding was applied for White Tiger which is the biggest oil field in Viet Nam. After a long time of waterflooding, water production becomes a serious problem in this field. Polymer gel treatment is simulated in full field scale and the results show that it is an excellent candidate for conformance control. Water production decreases from 4,800m3/d to slightly less than 2,000m3/d, while a significant increase in oil production has been achieved from unswept zones. That is a really successful evidence of the polymer conformance control technology in heterogeneous reservoirs.
Waterfloods increase both the oil rate and the volume of recoverable oil from a field, but they become very inefficient once the injected fluid channels through a reservoir directly to the production wells. High water production is a main concern in mature oil fields. A large amount of water production results in (a) the need for more complex water-oil separation techniques, (b) the rapid corrosion of well equipment, (c) the rapid decline in hydrocarbon recovery and (d) ultimately, the premature abandonment of a well. Also, the breakthrough of either the formation or injected water results in increased operational costs of pumping, treatment, and disposal of the produced water (Ogunberu, et al., 2006). As a result, the oil industry handles more water than oil.
For mature reservoirs, surfactant-polymer (SP) flooding is an attractive alternative to conventional waterflooding. However, it is a complicated process and the performance of SP flooding in complex reservoirs requires an accurate model that represents the reservoir features, chemical properties, and displacement mechanisms. This paper presents a successful application of miscible-tertiary SP flooding in an extremely heterogeneous reservoir. First, a series of numerical simulations in both homogeneous and heterogeneous cases were investigated and analyzed by a CMGTM simulator. Then a mathematical model was developed based on the Langmuir isotherm theory in order to fully integrate adsorption phenomenon into a reservoir model for controlling and reducing this effect during the SP flooding process. Small of polymer/surfactant adsorption leads to a small amount of chemical required for injecting and decreases operational cost.
Based on the above achievements, SP flooding was successfully applied for White Tiger - the biggest offshore oil field with high heterogeneity and complex geological characteristics in the Viet Nam continental shelf. An optimal range of operated conditions that include polymer solution properties, injection pressure and injection rates are proposed with the objective of optimizing the SP process in the White Tiger field. The simulation results show that SP flooding is the best recovery schemes in comparison with waterflooding, pure polymer flooding and pure surfactant flooding. A significant increase in oil production has been achieved by the effect of surfactant and polymer which is a really successful evidence of SP flooding in complex reservoirs.
The current high oil prices combined with the challenges of discovering and developing offshore and remote oil fields have made improving recovery from existing mature oil fields attractive. Surfactant polymer (SP) flooding is a promising method for enhanced oil recovery in complex reservoirs. Ideally, microemulsions are formed during SP flooding, which helps to solubilize and transport residual crude oil. The reduction in the interfacial tension (IFT) reduces the capillary forces which trap residual oil in place in porous media, making displacement of the oil easier. Because of low surface tension on the boundary of the micellar solution with the reservoir fluid, almost the entire oil is set in motion. The higher viscosities of micellar solution and polymer buffer slug allow for an increase in the displacement area. The fundamental mechanism of SP flooding is further discussed in the next section.