In naturally fractured reservoirs, oil recovery from waterflooding relies on the spontaneous imbibition of water to expel oil from the matrix into the fracture system. The spontaneous imbibition process is most efficient in strongly water-wet rock where the capillary driving force is strong. In oil- or mixed-wet fractured carbonate reservoirs, however, the capillary driving force for the spontaneous imbibition process is weak, and therefore the waterflooding oil recoveries are low. The recovery efficiency can be improved by dissolving low concentrations of surfactants in the injected water to alter the wettability of the reservoir rock to a more water-wet state. This wettability alteration accelerates the spontaneous imbibition of water into matrix blocks, thereby increasing the oil recovery during waterflooding. Several mechanisms have been proposed to explain the wettability alteration by surfactants, but none have been verified experimentally. Understanding of the mechanisms behind wettability alteration could help to improve the performance of the process and aid in identification of alternative surfactants for use in field applications. Results from this study revealed that ion-pair formation and adsorption of surfactant molecules through interactions with the adsorbed crude oil components on the rock surface are the two main mechanisms responsible for the wettability alteration. Previous researchers observed that, for a given rock type, the effectiveness of wettability alteration is highly dependent upon the ionic nature of the surfactant involved. Our experimental results demonstrated that ion-pair formation between the charged head groups of surfactant molecules and the adsorbed crude oil components on rock surface was more effective in changing the rock wettability toward a more water-wet state than the adsorption of surfactant molecules as a monolayer on the rock surface through hydrophobic interaction with the adsorbed crude oil components. By comparing two anionic surfactants with different charge densities, we propose that wettability alteration processes might be improved through the use of dimeric surfactants, which have two charged head groups and two hydrophobic tails. Gemini surfactants where the molecules are joined at the head end are likely to be effective when ion-pair formation is the wettability alteration mechanism, and bolaform surfactants, in which molecules are joined by the hydrophobic tails, should be more effective in the case of surfactant monolayer adsorption.

Heterogeneity of oil reservoirs often leads to unproductive cycling of injected oil recovery chemicals, resulting in the loss of significant quantities of reserves. To maximize recovery efficiency, a blocking agent may be placed deep into high-permeability channels so that the subsequently injected chemicals can be redirected into previously unswept regions. Cr(III)−polyacrylamide gels have been used extensively in field applications as blocking agents for sweep improvement; however, the gelation time of the current state-of-the-art is too short to achieve in-depth placement. This paper describes a novel approach of using polyelectrolyte complex nanoparticles to entrap and control the release Cr(III) to effectively extend gelation time. Self-assembly of polyethylenimine (PEI) and dextran sulfate (DS) resulted in the formation of ∼100−200 nm particles that efficiently entrapped chromium while maintaining colloidal stability in water or gelant. Although the addition of chromium chloride to HPAM typically produced gels in minutes, chromium was efficiently sequestered in nanosuspensions of polyelectrolyte complexes, resulting in a significant delay in gel formation that was dependent on pH, ionic strength, and temperature. The gel formation kinetics of PEI, polyelectrolyte complexes (PECs) of PEI and DS, and PECs loaded with chromium were compared. PEI, a known cross-linker of HPAM, produced a steady increase in gelant viscosity over time. PECs without chromium demonstrated a delayed gel formation compared to PEI but possessed a similar creeping increase in viscosity. In contrast, PECs loaded with chromium typically showed minimal viscosity increase over time followed by an abrupt viscosity increase, resulting in gel formation. This study suggests that PECs offer a flexible nanotechnology platform that may enable novel chemical delivery schemes in the oil and gas industry.

The discovery of a series of chromen-2-ones with selective affinity for the dopamine (DA) D4 receptor is described. Target compounds were tested for binding to cloned human DA D2L, D3, and D4.2 receptor subtypes expressed in Chinese hamster ovary K1 cells. Several compounds demonstrated high affinity (<20 nM, K(i)) and greater than 100-fold selectivity for DA D4.2 versus DA D2L receptors. The results of a SAR study are discussed within. In a DA D4 functional assay measuring [(3)H]thymidine uptake, target compounds showed antagonist activity at the D4.2 receptor. Compound 22, 7-[(2-phenylaminoethylamino)methyl]chromen-2-one, increased DOPA (L-3,4-dihydroxyphenylalanine) accumulation 51% in the hippocampus and 23% in the striatum of rat brains when dosed orally at 20 mg/kg.

No abstract

Guar-based polymer gels are used in the oil and gas industry to viscosify fluids used in hydraulic fracturing of production wells, in order to reduce leak-off of fluids and pressure, and improve the transport of proppants. After fracturing, the gel and associated filter cake must be degraded to very low viscosities using breakers to recover the hydraulic conductivity of the well. Enzymes are widely used to achieve this but injecting high concentrations of enzyme may result in premature degradation, or failure to gel; denaturation of enzymes at alkaline pH and high temperature conditions can also limit their applicability.In this study, application of polyelectrolyte nanoparticles for entrapping, carrying, releasing and protecting enzymes for fracturing fluids was examined. The objective of this research is to develop nano-sized carriers capable of carrying the enzymes to the filter cake, delaying the release of enzyme and protecting the enzyme against pH and temperature conditions inhospitable to native enzyme.Polyethylenimine-dextran sulfate (PEI-DS) polyelectrolyte complexes (PECs) were used to entrap two enzymes commonly used in the oil industry in order to obtain delayed release and to protect the enzyme from conditions inhospitable to native enzyme. Stability and reproducibility of PEC nanoparticles was assured over time.An activity measurement method was used to measure the entrapment efficiency of enzyme using PEC nanoparticles. This method was confirmed using a concentration measurement method (SDS-PAGE). Entrapment efficiencies of pectinase and a commercial high-temperature enzyme mixture in polyelectrolyte complex nanoparticles were maximized. Degradation, as revealed by reduction in viscoelastic moduli of borate-crosslinked hydroxypropyl guar (HPG) gel by commercial enzyme loaded in polyelectrolyte nanoparticles, was delayed, compared to equivalent systems where the enzyme mixture was not entrapped. This indicates that PEC nanoparticles delay the activity of enzymes by entrapping them. It was also observed that control PEC nanoparticles decreased both viscoelastic moduli, but with a slower rate compared to the PEC nanoparticles loaded with enzyme.Preparation shear and applied shear showed no significant effect on activity of enzyme-loaded PEC nanoparticles mixed with HPG solutions. However, fast addition of chemicals during the iv preparations showed smaller particle size compared to the drop-wise method. PEC nanoparticles (PECNPs) also protected both enzymes from denaturation at elevated temperature and pH.Following preparation, enzyme-loaded PEC nanoparticles were mixed with borate crosslinked HPG and the mixture was injected through a shear loop. Pectinase-loaded nanoparticles mixed with gelled HPG showed no sensitivity to shear applied along the shear loop at 25 °C. However, EL2X-loaded PEC nanoparticles showed sensitivity to shear applied along the shear loop at 40 °C.Filter cake was formed and degraded in a fluid loss cell for borate crosslinked HPG solutions mixed with either enzymes or...

The main production mechanism during water flooding of naturally fractured oil reservoirs is the spontaneous imbibition of water into matrix blocks and resultant displacement of oil into the fracture system. This is an efficient recovery process when the matrix is strongly waterwet. However, in mixed-to oil-wet reservoirs, secondary recovery from water flooding is often poor. Oil production can be improved by dissolving low concentrations of surfactants in the injected water. The surfactant alters the wettability of the reservoir rock, enhancing the spontaneous imbibition process. Our previous study revealed that the two main mechanisms responsible for the wettability alteration are ion-pair formation and adsorption of surfactant molecules through interactions with the adsorbed crude oil components on the rock surface. Based on the superior performance of surfactin, an anionic biosurfactant with two charged groups on the hydrophilic head, it was hypothesized that the wettability alteration process might be further improved through the use of dimeric or gemini surfactants, which have two hydrophilic head groups and two hydrophobic tails. We believe that when ion-pair formation is the dominant wettability alteration mechanism, wettability alteration in oil-wet cores can be improved by increasing the charge density on the head group(s) of the surfactant molecule since the ion-pair formation is driven by electrostatic interactions. At a concentration of 1.0 mmol L -1 a representative anionic gemini surfactant showed oil recoveries of up to 49% original oil-in-place (OOIP) from oil-wet sandstone cores, compared to 6 and 27% for sodium laureth sulfate and surfactin, respectively. These observations are consistent with our hypothesis.

Polyacrylamides are often used in water-based hydraulic fracturing for natural gas and oil production. However, residual polymer remaining in the fractured rock can limit production. A novel approach for degrading partially hydrolyzed polyacrylamide (HPAM) was investigated using hydrogen peroxide and horseradish peroxidase (HRP). This sustainable HRP/H 2 O 2 system degraded the polymer in solution, reducing its viscosity in both pure water and brine solutions. Molecular weight measurements confirmed that the viscosity reduction was due to a significant degradation of the polymer backbone and not primarily by other mechanisms such as amide hydrolysis or rearrangement, and so forth. The reduction in viscosity and molecular weight was first order with respect to H 2 O 2 concentration. The kinetics of viscosity reduction and molecular weight are closely correlated which would allow the quicker and simpler viscosity method to help engineer future processes.

No abstract