The Applicability of Surfactants on Enhancing the Productivity in Tight Formations

Abstract

Significant amounts of fracturing fluid are lost during hydraulic fracturing operations and it is believed that this fluid can hinder hydrocarbon production. For this reason, higher fracturing fluid recovery (flowback) might be desirable. One way to enhance the flowback is to reduce the capillary force within the formation. While the applicability of surfactants in conventional reservoirs that operate in tertiary production phase is fairly well understood, it is unclear whether these techniques can enhance the production in unconventional reservoirs that operate in the primary phase; and the magnitude of the enhancement that can be expected by using the surfactants as fracturing fluid additives. Here, we designed a coreflood sequence that simulated fracturing fluid invasion, flowback and hydrocarbon production in order to quantify the permeability damage due to fluid invasion. Furthermore, we evaluated the enhancements in hydrocarbon permeability due to the use of IFT reducing agents. Our results revealed a mechanism of permeability damage and indicated that improvements in hydrocarbon permeability observed with surfactant-supplemented fracturing fluids were due to the reduction of water trapping through matrix-fracture interaction and not to the capillary desaturation of the rock.

A Systematic Study on the Impact of Surfactant Chain Length on Dynamic Interfacial Properties in Porous Media: Implications for Enhanced Oil Recovery

“…Since the targeted reservoir samples were rich in calcite and quartz minerals, we decided to use outcrop samples, that is, Edwards limestone and Berea sandstone, as test porous mediums for surfactant screening steps using spontaneous imbibition. It is also reported in the literature that even though conventional and unconventional rocks have different properties, core flooding experiments performed on conventional rocks can provide relevant insights into the physics controlling the displacement mechanisms in rock samples obtained from unconventional reservoirs. , A helium porosimeter-permeameter was used to experimentally measure the porosity and permeability of the rocks as shown in Table . Figure shows two- and three-dimensional images of Edwards limestone and Berea sandstone rock samples obtained using high-resolution X-ray microtomography and scanning electron microscopy.…”

Roles of Surfactants during Soaking and Post Leak-Off Production Stages of Hydraulic Fracturing Operation in Tight Oil-Wet Rocks

“…The selection of the value of pressure drop (Δ P ) across both the type of cores is limited by the relation for Rapoport–Leas number (Δ P / P c ) provided by Liang et al Based on their study, they stated that under the conditional range of Δ P / P c < 10, the water-block is formed across the interface of the matrix and the fracture that leads to a reduction in the effective permeability of hydrocarbon during the production stage. Therefore, conservatively choosing the underlying condition of Δ P / P c =5, a semiempirical and iterative-explicit method of estimation of capillary pressure from permeability is employed to select the operating pressure drop.…”

“…Ibrahim and Nasr-El-Din have recently even conducted similar experiments in tight sandstones (0.23 mD) and in Marcellus shales (3.16 nD) to show similar behavior of regained permeability to gas, as discussed above. Similarly, for an oil/water system in a low-permeable water-wet rock (3–10 mD), the studies performed by Liang and co-workers − have also demonstrated the migration of water-block phenomenon using high-resolution CT-scans. Liang et al even concluded that for the case of an oil-wet rock, the water-block at the fracture–matrix interface does not exist but rather the end-point relative permeability for oil is subdued at the residual saturation of water due to the capillary entrapment of water in the bulk of the pore space and not along the walls of the pore space.…”

The Influence of Oil Composition, Rock Mineralogy, Aging Time, and Brine Pre-soak on Shale Wettability

“…The oil-wetness is believed to cause a greater effect in a tighter reservoir, i.e., shale oil reservoirs, due to the stronger boundary effect from the pore wall to the pore throat. To solve this problem, several authors have investigated the application of surfactants as an EOR (enhanced oil recovery) technique by altering the shale wettability from oil-wet to water-wet. − To design a surfactant system with strong wettability alteration performance, we must first understand the surface oil-wetting mechanism. This is important because minerals commonly found in the reservoir, i.e., quartz, calcite, dolomite, and clay, are actually water-wet after deposition.…”