The primary purpose of using surfactants in stimulating hydrocarbon rich gas reservoirs is to reduce interfacial tension, and/or modify contact angle and reservoir wettability. However, many surfactants either adsorb rapidly within the first few inches of the formation, or negatively impact reservoir wettability, thus reducing their effectiveness in lowering capillary pressure. These phenomena can result in phase trapping of the injected fluid adversely impacting oil and gas production. This study describes experimental and field studies comparing various common surfactants used in oil bearing formations including alcohol ethoxylates, EO-PO block copolymers, ethoxylated amines and a multi-phase complex nano fluid system to determine their impact on oil recovery and adsorption tendencies when injected through 5-foot and 1 ft sand columns. Ammot cell tests were used to evaluate imbibition of oil and water and a core flow apparatus was used to evaluate regained relative permeabilities. The results are correlated with surface energies of actual formation materials, oils and treating fluids. The results are used to select formulations containing surfactant, solvents and co-solvents to apply within the fracturing fluid to decrease adsorption, eliminate post treatment emulsions and improve oil and gas recovery in hydrocarbon rich gas wells.
This paper investigates the application of a proprietary surfactant-solvent package as an alternate chemical solution in Enhance Oil Recovery (EOR). This micro-emulsion system (MES) has many upsides to traditional solvent or surfactant-alone alternatives, as the package can be transported in-depth with less sacrificial adsorption yet maintain its interfacial tension reduction and oil swelling abilities to mobilize residual oil. While designing conformance jobs over the past several years, it has been observed that often times the injected fluids tend to travel through high permeability channels between a binary pair(s) of injector and producer. This short-circuit of injected fluids leaves residual oil in the channels and renders a large volume of the reservoir unswept. This paper examines the specific MES application where a high permeability channel is treated to mobilize the residual oil. The characteristic of the high permeability channel is based on production data and is comparatively relative to the total flood zone between a producer and an injector. Due to the small size of the channel the mobilized oil will be produced quickly resulting in attractive economics (due to smaller volume of treatment required). Due to quick response and attractive economics, there will be added incentive and field data to decide whether to expand the treatment on a field wide basis. Subsequently, the moving forward plan could be that once the treatment is validated, this process will be used in conjunction with conformance control along with Polymer as mobility control drive fluid for fieldwide expansion. Laboratory core flood experiment shows that a 1.0 PV slug of 1 gallons for thousand gallons (gpt) of the complex MES additives recovers about 9-12% OOIP (23-27% OIP). The experiment shows that an increase of oil cut from 1% to 12% occurs due to use of the complex MES. The laboratory experiment was performed with oil saturated Torrey Buff sandstone core. The results of this experiment were simulated using CMG's STARS simulation tool. The laboratory results were scaled up to test in two pilot configurations where the remaining oil in the channels was the primary target of the simulation exercise. The first pilot is a quarter 9-spot with one injector and three producers. The second pilot is a central injector in the up-dip of the structure with 5 producers. The simulation results show that the peak oil production due to the effect of the MES is very significant. The economic analysis indicates attractive returns over continued waterflood for both pilots.
Formation damage caused by water-in-crude oil emulsions can have a big impact on oil production. Chemical treatment is often applied by injecting surfactants known as demulsifiers to break the water-in-crude oil emulsions. Common demulsifiers used in the oilfield industry often contain chemicals that are deemed environmentally unacceptable. With the increasingly stringent environmental and safety measures for oilfield chemicals, there is a significant drive to develop more environmentally friendly formulations for oilfield applications that are as efficient as existing chemicals. In this work, more environmentally friendly demulsifiers have been developed by systematically upgrading existing components in a conventional demulsifier with more environmentally acceptable components. The environmental impact of existing and upgraded formulations was evaluated using industry developed product rating systems. Demulsification tests were then carried out to assess the performance of the newly developed formulations on several problematic oils.
A continuing challenge in hydraulic fracturing of tight gas formations is associated with remediation of formation damage caused by fluid invasion into the porous media. Numerous studies documenting the use of complex nanofluids and surfactants to remediate formation damage have been reported. Recent publications have demonstrated that complex nanofluid additives resulted in lower pressures to displace injected frac fluids over conventional surfactants, and led to greater enhancement of gas and water production. These findings were also confirmed by several recent statistical analyses that took into consideration differences in the properties of treated wells. Many field case studies and supplementary laboratory data have illustrated benefits of complex nanofluid treatment over conventional surfactants. While these publications describe the successes of complex nanofluid treatment, the influence that the formulation composition has on its performance has not been fully investigated. In the present study, we prepared complex nanofluids with different chemical compositions and examined their performance in fluid recovery tests using columns packed with sand, ceramic proppant, and shale, as well as their ability to enhance permeability of sandstone cores to gas. We have established that performance of complex nanofluids in these applications was dependent on the amount of microemulsifed solvent in the original formulations and that optimal performance across all applications was achieved with a complex nanofluid formulation with a near-balanced composition.
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