The Research on Weak Alkali ASP Compound Flooding System for Shengli Heavy Oil

In order to avoid the disadvantages caused by strong alkali used in enhanced oil recovery, sodium metaborate was compounded with nonionic surfactant nonylphenol polyoxyethlene polyoxypropylene ether sulfate and hydrolyzed polyacrylamide for the first time as a chemical displacement agent for Shengli heavy oil. The interfacial tension between crude oil and aqueous solutions, emulsification tests, microscopic displacement properties and sandpack flooding were investigated. It can be observed that the interfacial tension was reduced to ultra-low value due to the synergy effect between the weak alkali and surfactant. The microscopic displacement tests showed that there was an optimum surfactant concentration for alkali-surfactant flooding system to obtain larger sweep efficiency. And the recovery efficiency can be further increased by addition of hydrolyzed polyacrylamide. The oil recovery increased with the increasing of hydrolyzed polyacrylamide concentration. The newly designed compound system was proven to have the application potential on pilot tests.Key words: Weak alkali; Sodium metaborate; Compound flooding system; Nonylphenol polyoxyethlene polyoxypropylene ether sulfate; Heavy oi

Preparation and Characterization of Gemini Surfactant Intermedium

This paper studies the preparation process and characterization of gemeni-diol, an intermedium compound for synthesizing anionic gemini surfactant. Firstly, as a material to synthesize anionic gemini surfactant, high purity ethylene glycol diglycidyl ether (EGDGE) is obtained by distill epoxy resin thinner at a reduced pressure. Based on gas chromatogram, 94.51 percent of liquid at cut points of 116-119℃/5mmHg is EGDGE. Then the effects of catalyst and reaction time on the reaction of nonylphenol and EGDGE are investigated. The results show the optimized conditions to synthesize gemini-diol are as following: using 0.25%KOH and 0.25% phosphorus triphenyl as catalyst to keep the reaction of nonylphenol and EGDGE at 110℃ for 3-5h. The yield of gemini-diol is 88.2% under these conditions

The Effect of Betaine Surfactant on Carbonate Reservoir Wettability in Self-Diverting Acidizing Stimulation

Contact angle alterations of carbonate cores after immersing in spent acid with oleyl amido propyl betaine surfactant were measured to clarify the effect of viscoelastic surfactant on the wettability of carbonate reservoir during self-diverting acidizing. The results showed that spent acid solutions with hydrochloric acid and betaine surfactant induced core wettability to water-wetting for initially oil-wet rocks, and oil-wetting for initially water-wet rocks. Longer immersion time and higher concentration of surfactant enhanced the effects. The adverse wettability reversal for water-wet reservoir was eliminated by mutual solvent or brine postflush. Chemical mechanisms of the wettability alteration were interpreted

Preparation of high-temperature gels for enhanced oil recovery using methyl etherized melamine-formaldehyde resin

Polymer gels are the most commonly used materials in the petroleum industry for reservoir conformance control and resolving excessive water production problems. In this study, high-temperature gels were prepared with HPAM or AM/AMPS as the gel-forming agent, methyl etherified melamineformaldehyde resin (MEMFR) as the crosslinker, and nano-silica as the stabilizer, and their properties were evaluated. The results showed that HPAM-MEMFR gels were unstable at 110°C in a brine of 20665 mg/L. AM/AMPS-MEMFR gels are stable at 110°C, with gelation time ranging from 15 h to 92 h and storage modulus ranging from 3.6 Pa to 50 Pa. AM/AMPS-MEMFR gel has less than 10% dehydration after aging at 110°C for 90 days, almost no shrinkage in volume, and a significant increase in strength, making it suitable as a gel material for enhanced oil recovery

Influence of Oil Viscosity on Alkaline Flooding for Enhanced Heavy Oil Recovery

Oil viscosity was studied as an important factor for alkaline flooding based on the mechanism of “water drops” flow. Alkaline flooding for two oil samples with different viscosities but similar acid numbers was compared. Besides, series flooding tests for the same oil sample were conducted at different temperatures and permeabilities. The results of flooding tests indicated that a high tertiary oil recovery could be achieved only in the low-permeability (approximately 500 mD) sandpacks for the low-viscosity heavy oil (Zhuangxi, 390 mPa·s); however, the high-viscosity heavy oil (Chenzhuang, 3450 mPa·s) performed well in both the low- and medium-permeability (approximately 1000 mD) sandpacks. In addition, the results of flooding tests for the same oil at different temperatures also indicated that the oil viscosity put a similar effect on alkaline flooding. Therefore, oil with a high-viscosity is favorable for alkaline flooding. The microscopic flooding test indicated that the water drops produced during alkaline flooding for oils with different viscosities differed significantly in their sizes, which might influence the flow behaviors and therefore the sweep efficiencies of alkaline fluids. This study provides an evidence for the feasibility of the development of high-viscosity heavy oil using alkaline flooding

Research on foaming agents for gas flooding in medium-temperature and high-salinity clastic reservoirs

Anionic surfactants are commonly used as foaming agents in foam-enhanced oil recovery, but their performance is seriously affected by high temperature and high salinity environment. However, there are not many studies on the adsorption pattern and salinity resistance performance of anionic surfactants on solid surfaces. This study evaluated the foaming performance of several anionic surfactants suitable for hightemperature, high-salinity salinity reservoirs. It was found that α-olefin sulfonate (AOS) showed good foaming performance under high temperature and high salt condition. However, the solubility of the foaming agent was low in brine with a salinity of 11×104 mg·L-1. Therefore, a co-solvent (ABS), which is a strong hydrophilic alkyl benzene sulfonate, was chosen to be compounded with AOS in this study. In this study, a foaming agent with excellent foaming performance and solubility at a temperature of 90°C and a salinity of 11×104 mg·L-1 was constructed. The adsorption of the foaming agent was less than 0.3mg/g on the surface of quartz sand, and its foaming rate and foam decay half-life after three adsorptions maintained more than 85% of the original performance. The results of the study can guide the selection of foaming agents for gas injection and mobility control in medium temperature and high salinity clastic reservoirs

Development of high strength polyvinyl alcohol gel for water shutoff in carbonate reservoirs

To provide a high-strength, non-resin organic plugging agent for water shutoff in carbonate fracture and cave reservoirs, a high-strength gel was prepared with polyvinyl alcohol 1788 as gelant and p-phthalaldehyde as crosslinker in this study. By selecting latent acids rather than strong acid such as hydrochloric acid and sulfuric acid as catalysts, and by adding clay and sulphonated phenolic resin as stabilisers to the gelation, the drawbacks of short gelation time of polyvinyl alcohol and high dehydration rate of the formed gel soaking in brine were overcame. The evaluation results showed that the gellant composed of 7wt% polyvinyl alcohol, 4wt% clay, 0.3wt% aldehyde crosslinker, 0.25wt% latent acid, 1.5wt% sulfonated phenolic resin, and 0.3wt% hexamethylenetetramine had a gelation time of 2 h at 130 °C. The storage modulus of the gel was up to 2000 Pa, and the dehydration rate of the gel after soaking in synthetic brine for 30 days was less than 15%. Furthermore, the breakthrough pressure gradient in a slim tube with a diameter of 3mm reached 15 MPa / m, which indicated that the gel is a temperature and salinity resistant plugging agent with strong plugging ability

Syneresis Behavior of Polymer Gels Aged in Different Brines from Gelants

Gel syneresis is a common problem in gel treatment for oil recovery applications. In this study, a stable gel was prepared in a soft brine by using a water-soluble phenolic resin as a crosslinker, nanoparticles as a stabilizer, and partially hydrolyzed polyacrylamide (HPAM) or copolymers with different contents of 2-acrylamido-2-methylpropane sulfonic acid (AMPS) groups as polymers. The syneresis behavior of the gels formed in a soft brine was evaluated upon aging in hard brines. The results show that when the salinity of the hard brine is lower than 30,000 mg/L, the gel expands, and its strength decreases; when the salinity of the hard brine is higher than 50,000 mg/L, the gel exhibits syneresis, and its strength increases. The effects of various influencing factors on the gel syneresis behavior were also evaluated. It was found that optimizing the polymer structure and adding nanoparticles can effectively overcome gel syneresis and enhance gel stability. Based on the research described in this paper, some proposals for designing salt-resistant polymer gels are presented