Surfactants have been used for decades to enhance the production of hydrocarbons from oil-bearing subterranean formations. Production improvement is tied to optimization of the interaction of surfactant within a given oil/water/rock system. Ideal surfactants will alter the wettability and water/oil interfacial tension. While the mechanism of interfacial tension reduction is well-established, the mechanism of surfactant-driven wettability alteration is still up for discussion. This study aims to give insight into the matter by investigating the surfactant adsorption and desorption process using a quartz crystal microbalance with dissipation (QCM-D) apparatus. QCM-D is, in essence, an ultra-sensitive mass balance with nano-gram sensitivity. This technique exposes a sensor to flowing fluid at a controlled temperature and directly measures surface associations through the change in mass over time. Altering the material composition of the sensor surface, SiO2 for quartz and CaCO3 for calcite, and modifying the wettability with North American oil samples gives better representation of the surface interactions present in oil producing reservoirs. Surface activity for an anionic, cationic, non-ionic, and microemulsion surfactant were evaluated to determine both static and dynamic adsorption properties. The surfactant systems have drastically different static and dynamic adsorption properties. The charged surfactant had no measurable interaction with the quartz surface at 1 gallon per 1000 gallons (gpt). At higher concentrations the cationic surfactant reacted more slowly than the anionic and left more residual mass on the quartz and carbonate surfaces. Non-ionic surfactants had more measurable mass even at lower concentrations and the non-microemulsion had faster adsorption kinetics and was more resistant to washing off with fresh water than the microemulsion. The impact of job design for the various surfactant interactions with the silica surface was evaluated by altering the pumping schedules for the same volume of surfactant, showing the difference in accumulated residual mass on the surface using low concentrations throughout the fluid or front loading a concentrated plug volume. For charged surfactants, front loading was the least effective method; consistent concentration throughout the pumping schedule was more effective. Fast adsorbing surfactants quickly saturated the surface at high concentrations and had more effective loadings by splitting the surfactant into two equal medium concentration plugs. Ultimately, the surfactants were evaluated for removal of oil from the quartz surface. Without surfactant, very little oil is removed from the surface and it remained oil wet and fluorescent; the addition of surfactant improved the oil recovery by vastly different mechanisms. This study provides an understanding of surfactant adsorption processes on rock surfaces and the role of job design for mobilizing hydrocarbons. Understanding surfactant adsorption and its effect on wettability improves the current understanding on the matter.
Thermally-activated, single-component resin formulations in which the catalyst is included in the resin composition can be challenging to place over intervals longer than 30 feet (9.1 meters). Despite the proven consolidation performance observed with epoxy-based systems, initial viscosity and rapid reactivity leading to short placement times have resulted in the industry seeking alternative chemistries to enhance formation integrity. Herein we report the development of a 2-stage formation consolidation system entailing a hetero-aromatic-based resin composition that, once placed downhole, will only begin curing with subsequent introduction of an activation fluid. The latent property of the updated resin formulation allows for extended lateral applications, and incorporating a new surface modifying agent allows for the treatment of formations with an excess of 20% wt—clay mineralogy.
The water-sensitive nature of shale is traditionally thought to be a factor of the clay content of the rock. Because current practices to mitigate formation damage entail the use of brines to control the osmotic potential of stimulation fluids, we posited that not all brines will induce the same response from Bentonite, Illite, and more importantly shale. Current industrial practices to mitigate permeability damage in source rock shale reservoirs typically entail the use of sodium-, potassium-, calcium-, tetramethyl ammonium-, and/or choline chloride salt brines to control the rate of cation exchange between formation clays and stimulation fluids. Industrial and literature precedent suggests that below a critical salt concentration (CSC) osmostically-driven cation-exchange between injected fluid and the formation is the primary damage mechanisms for both swelling and migrating clays; however, above the CSC, the potential still exists for crystalline swelling and mechanical destabilization. Examining various clays and clay laden formation materials revealed that certain cations, even above their CSC, will induce formation damage. To accurately assess the effect and permanency of various brines when introduced to pure clay as well as shales, a statistically relevant laboratory protocol has been developed to evaluate the role differing cations play in shale preservation. The clay and formation cuttings were evaluated for swelling and mechanical stability, then subjected to dynamic experiments using sandpack, coreflow, and API conductivity testing methods. The evaluated formation materials were diagnosed with computed tomography (CT), scanning electron microscopy (SEM), and energy-dispersive X-ray spectroscopy to diagnose permeability damage mechanisms for given treatment fluids and formation material composition. This paper seeks to advance the existing understanding of the damage mechanisms involved when brine containing stimulation fluids are introduced to shale reservoirs. Currently, there is a lack of consensus on the significance of the identity of the ideal salt-cation treatment to preserve permeability in shale reservoirs. The authors have probed the effect various brines have on clay and unconventional material, which compliments the current body of literature related to shale inhibition.
This paper describes the development of a highly automated apparatus and customized software package to rapidly evaluate the performance of surfactant additives in dry gas shale reservoirs. A major challenge throughout the industry is the ability to reduce water saturation resulting from fluid leakoff into the formation matrix during stimulation operations. The new method presented in this paper to help identify the optimum surfactant for reducing post-treatment water saturation based on well-specific parameters. Conventional laboratory evaluation of stimulation fluid additives typically involves coreflow studies, which are excessively time consuming and have poor reproducibility as a result of core-to-core inconsistencies. The focus of this endeavor was to develop a statistically relevant method that can use drill cuttings samples and measures surfactant additive performance data with high confidence and reproducibility for the tested formation material. Data analysis included analysis of variance (ANOVA) followed by post-hoc Tukey honest significant difference (HSD) range testing. Test apparatus results were also corroborated with coreflow studies. Eight surfactant additives were evaluated in the presence of four different fracture fluid formulations and formation samples. For each surfactant/fracturing fluid/formation test matrix, the software was able to rank surfactants performance based on the volume of fracturing fluid displaced from a column pack normalized to the pressure gradient. No individual surfactant performed best more than 40% of the time within this test series, and the surfactant-laden formulations always statistically outperformed the nonsurfactant control. The results imply that the addition of surfactants results in increased treatment fluid load recovery. Reservoir simulations were performed to investigate the effects of increased load recovery and depth of invasion of fracturing fluids on hydrocarbon production. The simulation results confirmed the assumption that minimal invasion of treatment fluid into the matrix of the formation resulting from increased load recovery does improve hydrocarbon production. The simulation data also suggest this observed hydrocarbon production improvement is particularly prevalent in the early time/cleanup period of the life of the well. A key feature and novelty of the apparatus is the ability to evaluate numerous surfactants in series and the potential to perform up to 24 individual tests in an 8-hour shift. The results presented in this paper showcase the utility of the newly developed apparatus, which offers a new method for rapid customization of stimulation fluids.
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