Abstract In-situ gelled acids have been used for acid diversion in heterogeneous carbonate reservoirs for more than two decades. Most of the gelled systems are based on an anionic polymer that has a cleaning problem after the acid treatments that leads to formation damage. This work evaluates a new cationic-polymer acid system with the self-breaking ability for the application as an acid divergent in carbonate reservoirs. Experimental studies have been conducted to examine the rheological properties of the polymer-based acid systems. The apparent viscosities of the live and the partially neutralized acids at pH from 0 to 5 were measured against the shear rate (0 to 1,000 s-1). The impact of salinity and temperature (80 to 250°F) on the rheological properties of the acid system was also studied. The viscoelastic properties of the gelled acid system were evaluated using an oscillatory rheometer. Dynamic sweep tests were used to determine the elastic (G’) and viscous modulus (G") of the system. Single coreflood experiments were conducted on Indiana limestone cores to study the nature of diversion caused by the polymer-acid system. The impact of permeability contrast on the process of diversion was investigated by conducting dual coreflood experiments on Indiana limestone cores which had a permeability contrast of 1.5-20. CT scans were conducted to study the propagation of wormhole post acid injection for both single and dual corefloods. The live acid system displayed a non-Newtonian shear-thinning behavior with the viscosity declining with temperature. For 5 wt% HCl and 20 gpt polymer content at 10 s-1, the viscosity decreased from 230 to 40 cp with temperature increasing from 88 to 250°F. Acid spending tests demonstrated that the acid generated a gel with a significant improvement in viscosity to 260 cp (at 250°F and 10 s-1) after it reached a pH of 2. The highly viscous gel plugged the wormhole and forced the acid that followed to the next higher permeability zone. The viscosity of gel continued to increase until it broke down to 69 cp (at 250°F and 10 s-1) at a pH of 4.8, which provides a self-breaking system and better cleaning. Coreflood studies indicated that the wormhole and the diversion process is dependent on the temperature and the flow rate. There was no indication of any damage caused by the system. The injected acid volume to breakthrough (PVBT) decreased from 2.2 to 1.4 when the temperature increased from 150 to 250°F. The strong elastic nature of the gel (G’= 3.976 Pa at 1 Hz) formed by the partially neutralized acid system proves its suitability as a candidate for use as a diverting agent. This novel acid-polymer system has significant promise for usage in acid diversion to improve stimulation of carbonate reservoirs.
Experimental and field studies have indicated that surfactants enhance oil recovery (EOR) in unconventional reservoirs. Rock surface wettability plays an important role in determining the efficacy of this EOR method. In these reservoirs, the initial wettability of the rock surface is especially important due to the extremely low porosity, permeability, and resulting proximity of fluids to the solid surface. This study is designed to investigate the effect of oil components, rock mineralogy, and brine salinity on rock surface wettability in unconventional shale oil/brine/rock systems. Six crude oils, seven reservoir rocks, and seven reservoir brine samples were studied. These oil samples were obtained from various shale reservoirs (light Eagle Ford, heavy Eagle Ford, Wolfcamp, Middle Bakken, and Three Forks) in the US. SARA (saturates, aromatics, resins and asphaltenes) analysis was conducted for each of the crude oil samples. Additionally, this study also aims to provide a guideline to standardize the rock sample aging protocol for surfactant-related laboratory experiments on shale reservoir samples. The included shale reservoir systems were all found to be oil-wet. Oil composition and brine salinity showed a greater effect on wettability as compared to rock mineralogy. Oil with a greater amount of aromatic and resin components and higher salinity rendered the surface more oil-wet. Rock samples with a higher quartz content were also observed to increase the oil-wetness. The combination of aromatic/resin and the quartz interaction resulted in an even more oil-wet system. These observations are explained by a mutual solubility/polarity concept. The minimum aging time required to achieve a statistically stable wettability state was 35 days according to Tukey's analysis performed on more than 1100 contact angle measurements. Pre-wetting the surface with its corresponding brine was observed to render the rock surface more oil-wet.
In this paper, we present a simulation case study of a surfactant huff ’n’ puff pilot in the black oil window of the Eagle Ford (EF) Shale. The target horizontal well, which had been depleted for nearly 8 years, underwent stimulation via a surfactant huff ’n’ puff treatment. The surfactant was selected through laboratory screening using reservoir rock and fluid samples. After a 17-hour injection and a 1-month shut-in period, the well’s production increased fivefold from the baseline oil rate, sustaining incremental oil production for at least 2 years. The surfactant enhances oil recovery by altering rock wettability toward a more water-wet state and moderating oil/water interfacial tension (IFT). This process is modeled by surfactant adsorption in the simulator, indicating the degree of dynamic changes in relative permeability (krl) and capillary pressure (Pc) curves. We propose a comprehensive workflow comprising three stages: development of core-scale and field-scale models, sequential model calibrations, and multiobjective optimization to integrate laboratory measurements and field data from this pilot into multiscale numerical simulations. By matching oil recoveries from imbibition experiments on the core model and field production histories on the field model, krl and Pc profiles of two extreme states, basic reservoir properties, and additional reservoir properties altered during huff ’n’ puff operations are characterized. The matched core model reproduces a 15.1% incremental oil recovery for surfactant-assisted spontaneous imbibition (SASI) process relative to pure brine imbibition process. The matched reservoir model predicts the surfactant huff ’n’ puff treatment increases the oil production by 21.9% relative to water huff ’n’ puff treatment and by 52.9% relative to primary depletion for a 4-year period. The calibrated reservoir model also serves as a base case for optimizing well operation schedules through the implementation of a multiobjective genetic algorithm. The surfactant injection rate, injection time, and well shut-in time of the base case are varied to achieve higher oil production and reduced surfactant usage. Statistical analysis of eight trade-off cases indicates that optimal well operations, compared with existing practices, frequently involve increased injection rates [16.6–18.9 barrels per minute (bpm)], shorter injection periods (10–11.3 hours), and prolonged shut-indurations (49–65 days). This workflow offers valuable insights into surfactant huff ’n’ puff treatments for unconventional reservoirs, thereby facilitating the optimization of well operations and maximizing tertiary oil recovery.
Summary In-situ gelled acids are used for acid diversion in heterogeneous carbonate reservoirs. However, most of the gelled systems are based on anionic polymers that are difficult to clean up after the acid treatments. Residual polymer deposition leads to formation damage by blocking pore throats in the matrix. This work evaluates a new cationic-polymer acid system with self-breaking ability for application as an acid diverter in carbonate reservoirs. Experimental studies have been conducted to examine the rheological properties of these polymer-based acid systems. The apparent viscosities of the live and the partially neutralized acids at pH from 0 to 5 were measured against the shear rate (0 to 1000 s−1). The effects of salinity and temperature (80 to 250°F) on the rheological properties of the acid system were also studied. The viscoelastic properties of the gelled acid system were evaluated using an oscillatory rheometer. Dynamic sweep tests were used to determine the elastic (G′) and viscous (G″) moduli of the system. Single-coreflood experiments were conducted on Indiana limestone cores to study the nature of diversion caused by the polymer-acid system. The effect of permeability contrast on the process of diversion was investigated by conducting dual-coreflood experiments on Indiana limestone cores that had permeability contrasts of 1.5 to 20. Computed tomography (CT) scans were conducted to study wormhole propagation after acid injection for both single and dual cores. The live acid system displayed a non-Newtonian shear-thinning behavior with the viscosity declining as temperature increased. For 5 wt% hydrochloric acid (HCl) and 20 gal/t polymer content at 10 s−1, the viscosity decreased from 230 to 40 cp as the temperature increased from 88 to 250°F. Acid-spending tests demonstrated that the acid generated a gel with improved viscosity of 260 cp (at 250°F and 10 s−1) after it reached a pH of 2. The highly viscous gel plugged the wormhole and forced the acid that followed to the next higher-permeability zone. The viscosity of the gel continued to increase until it broke down to 69 cp (at 250°F and 10 s−1) at a pH of 4.8, which indicates a self-breaking system and more thorough cleanup potential. Coreflood studies indicated that the wormhole and the diversion process are dependent on the temperature and the flow rate. There was no indication of any damage caused by the system. The injected acid pore volume to breakthrough (PVBT) decreased from 2.2 to 1.4 when the temperature increased from 150 to 250°F. The strong elastic nature of the gel (G′ = 3.976 Pa at 1 Hz) formed by the partially neutralized acid system proves its suitability as a candidate for use as a diverting agent. This new acid-polymer system has significant promise for use in acid diversion to improve stimulation of carbonate reservoirs.
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