The numerical study of a 10 degree of freedom impact oscillator is presented. The mathematical model consists of a linear array of masses in which each mass is connected to its nearest neighbor by identical springs and dashpots. One end mass is attached to a rigid support while the other is free to impact a sinusoidally vibrating rigid table. Bifurcation diagrams based on the impact Poincare map are obtained over the entire range of natural frequencies, taking the table frequency as the bifurcation parameter. The diagrams reveal many chaotic bands as well as a wide variety of period-(n,m) (P,l,,,) orbits, where n is the period with respect to the impact PoincarC map and m is the number of table periods.

Surfactant Polymer flooding (SP flooding) has drawn more attention than Alkaline Surfactant Polymer flooding (ASP flooding) in China due to the difficulty of demulsification and the scale formation problem from the alkali in ASP. Traditionally, the primary requirement for the surfactant in SP flooding is the lowest interfacial tension (IFT). However, core flooding tests performed in a series of heterogeneous models have demonstrated there exist optimized surfactant IFT and polymer viscosity for SP flooding, which can maximize the oil recovery of a heterogeneous formation. The optimized surfactant IFT has a low value but not the lowest possible value, and polymer viscosity is at an appropriately high value, but not the highest possible value. This paper summarizes and analyzes more than 40 core flooding test results and provides possible mechanisms for the results.

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Overview Currently available primary- and secondary-oil-production technologies leave behind two-thirds of the oil in place as stranded oil. However, many analysis and field projects have shown that significant oil-recovery increases are possible with improved/enhanced oil recovery (EOR) by gas injection, thermal recovery, or chemical injection. The first two methods have proved cost-effective even at low oil prices. Current oil prices have created renewed interest in more-costly chemical-based EOR methods such as gel treatment, foam flooding, polymer flooding, alkaline/surfactant/polymer (ASP) flooding, and alkaline flooding. This year, we focus on chemical-based EOR methods. Chemical-EOR methods focus on improving the sweep efficiency by correcting reservoir heterogeneity or controlling fluid mobility, or they focus on increasing displacement efficiency by reducing residual-oil saturation. Gel treatment usually is intended to improve sweep efficiency and to reduce excess water production in channeled or fracture-dominated mature reservoirs. A newer trend in gel treatment is to apply preformed gels for in-depth treatments. These gels have been reported to penetrate deeply into superhigh-permeability streaks or fractures and seal or partially seal them off, thus creating high flow resistance in formerly watered-out, high-permeability zones. When successful, these gel systems divert a portion of the injection water into areas not previously swept by water. Foam flooding often is used to reduce gas mobility and to correct reservoir heterogeneity and increase sweep efficiency for gasflooding. Foam can be injected into the reservoir by coinjection of gas and surfactant solution or by injection of surfactant solution alternating with gas (SAG). Foam stability, surfactant-adsorption reduction, and optimized SAG-process design are the keys to controlling the economics of foam flooding. Polymer flooding is designed to control mobility for waterflooding. High-molecular-weight and new high-temperature salt-resistant polymers have made polymer flooding more economical. Adding either an alkaline or surfactant chemical, or both, in a polymer flood will scour residual oil from the rock, resulting in higher oil recovery than with polymer flooding alone. However, the scale problem associated with alkaline limits the use of ASP flooding. Wettability is of major importance to oil recovery, especially for fractured oil-wet carbonate reservoirs where water flows through the fractures but does not imbibe into the matrix because of negative capillary pressure. The chief concern is to develop cost-effective chemical formulations that change the carbonate wettability from oil-wet to water-wet. EOR/IOR additional reading available at the SPE eLibrary: www.spe.org SPE 107095 "Field-Scale Wettability Modification—The Limitations of Diffusive Surfactant Transport" by W.M. Stoll, SPE, Shell International E&P, et al. SPE 107776 "Improved ASP Design Using Organic-Compound/Surfactant/Polymer for La Salina Field, Maracaibo Lake" by E. Guerra, PDVSA Intevep, et al. SPE 107727 "Polymer Flooding: A Sustainable Enhanced Oil Recovery in the Current Scenario" by Ivonete P. Gonzalez da Silva, Petrobras, et al. SPE 106901 "SAGD Optimization With Air Injection" by J.D.M. Belgrave, EnCana Corporation, et al.

The drive to mitigat water production continues to increase the interest in applying conformance-control gel treatments in mature oil fields. Practically, designs of new gel treatments are adopted from previous case histories conducted in analogous reservoirs. This design-by-analogy procedure requires reservoir engineers to have a thorough knowledge about how gel treatments should be designed and have been mostly applied for each reservoir type. This paper presents comprehensive design guidelines for sizes of injection-well gel treatments based on an integrated survey of worldwide field projects. It also provides the typical and most-applied treatment volumes per reservoir type to be used as a starting point in planning of new jobs. The survey includes 61 gel projects compiled from SPE papers and conducted in 11 different countries between 1985 and 2014. Summaries and distributions of five gel-volume parameters were evaluated using the univariate descriptive analysis and stacked histograms. Scatterplots were used to determine effects of the formation temperature and the treatment timing on treatment volumes. The unsuccessful pilots were compared with productive gel projects to indicate the causes of pilots’ failure. The survey showed that the typical treatment size is 10,700 barrels, 310 barrel per perforated foot, or 19% of the moveable-pore-volume (MPV) of problem zones. Overall, gel volumes are greatly affected by the formation type and larger treatment volumes are placed in sandstones than carbonates and in matrix-rock than other formation types. Frequently, matrix-rock formations are treated with gel volumes >100 bbl/ft while treatment sizes <100 bbl/ft are used to treat naturally-fractured and unconsolidated formations. Gel volumes <3000 or even <1000 barrels are used to treat pipe-like channels in unconsolidated sandstones, treat matrix-rock formations without crossflow, or in economically-designed gel treatments. We have found that increasing the gel volume improves all treatment performances, not just the oil production response, and for all formation types, not just for the matrix-rock reservoirs. Hence, the ‘bigger is better’ rule of the gel volume is also recommended for fractured and unconsolidated formations as for the matrix-rock reservoirs. Instead of searching the literature for few analogs, the new survey provides conformance specialists with a complete overview of gel treatment sizes for all reservoir types. This would markedly facilitate designing of gel treatments and save time needed to identify the analogs for a given candidate reservoir.