Preparation and Properties of Reversible Emulsion Drilling Fluid Stabilized by Modified Nanocrystalline Cellulose.

Reversible emulsion drilling fluids can concentrate the advantages of water-based drilling fluids and oil-based drilling fluids. Most of the existing reversible emulsion drilling fluid systems are surfactant-based emulsifier systems, which have the disadvantage of poor stability. However, the use of modified nanoparticles as emulsifiers can significantly enhance the stability of reversible emulsion drilling fluids, but ordinary nanoparticles have the disadvantages of high cost and easily causing environmental pollution. In order to solve the shortcomings of the existing reversible emulsion drilling fluid system, the modified nanocrystalline cellulose was considered to be used as an emulsifier to prepare reversible emulsion drilling fluid. After research, the modified nanocrystalline cellulose NWX-3 can be used to prepare reversible emulsions, and on this basis, reversible emulsion drilling fluids can be constructed. Compared with the reversible emulsion drilling fluid stabilized by HRW-DMOB (1.3 vol.% emulsifier), the reversible emulsion drilling fluid stabilized by the emulsifier NWX-3 maintained a good reversible phase performance, filter cake removal, and oily drill cuttings treatment performance with less reuse of emulsifier (0.8 vol.%). In terms of temperature resistance (150 °C) and stability (1000 V < W/O emulsion demulsification voltage), it is significantly better than that of the surfactant system (temperature resistance 120 °C, 600 V < W/O emulsion demulsification voltage < 650 V). The damage of reservoir permeability of different types of drilling fluids was compared by physical simulation, and the damage order of core gas permeability was clarified: water-based drilling fluid > reversible emulsion drilling fluid > oil-based drilling fluid. Furthermore, the NMR states of different types of drilling fluids were compared as working fluids, and the main cause of core permeability damage was the retention of intrusive fluids in the core.

Class-III Hydrate Reservoir Depressurization Production Enhancement by Volume Fracturing and Cyclic N2 Stimulation Combination.

The depressurization effect is limited to class III hydrate reservoir recovery. To improve the depressurization effect, a new method of volume-fracturing and cyclic N2 stimulation combination (VFCS) was proposed. The production performance of this method was investigated by using numerical models based on reservoir parameters of the SH7 hydrate site in the South China Sea. The results show that (1) VFCS can greatly enhance the production performance with the average CH4 production rate being approximately 2.85 times higher than that of pure depressurization. This method combines the effects of volume fracturing and cyclic N2 stimulation by improving the seepage environment and further reducing the CH4 partial pressure in the gas phase. (2) High reservoir permeability, medium hydrate saturation, large volume-fracturing scale, low bottom-hole pressure, and high N2 injection amount can increase CH4 production by VFCS. (3) Although VFCS has the largest CH4 production volume and the highest hydrate dissociation degree among the studied production strategies, the reservoir temperature drop is significant by VFCS and future studies can be focused on the external heat supply to the reservoir to further improve the production.

Optimized polymer enhanced foam flooding for ordinary heavy oil reservoir after cross-linked polymer flooding.

A successful cross-linked polymer flooding has been implemented in JD reservoir, an ordinary heavy oil reservoir with high permeability zones. For all that, there are still significant volumes of continuous oil remaining in place, which can not be easily extracted due to stronger vertical heterogeneity. Considering selective plugging feature, polymer enhanced foam (PEF) flooding was taken as following EOR technology for JD reservoir. For low cost and rich source, natural gas was used as foaming gas in our work. In the former work, the surfactant systems CEA/FSA1 was recommended as foam agent for natural gas foam flooding after series of compatibility studies. Foam performance evaluation experiments showed that foaming volume reached 110 mL, half-life time reached 40 min, and dimensionless filter coefficient reached 1.180 when CEA/FSA1 reacted with oil produced by JD reservoir. To compare the recovery efficiency by different EOR technologies, series of oil displacement experiments were carried out in a parallel core system which contained cores with relatively high and low permeability. EOR technologies concerned in our work include further cross-linked polymer (C-P) flooding, surfactant-polymer (S-P) flooding, and PEF flooding. Results showed that PEF flooding had the highest enhanced oil recovery of 19.2 % original oil in place (OOIP), followed by S-P flooding (9.6 % OOIP) and C-P flooding (6.1 % OOIP). Also, produced liquid percentage results indicated PEF flooding can efficiently promote the oil recovery in the lower permeability core by modifying the injection profile.