Description of the Paper: The U-A reservoir unit is an eolian deposition where the primary facies are dune deposits. These sands are composed of quartz grains with feldspars. These grains are large in diameters and coated with illite clays, which made the formation sand friable. These sands require sand control and one of the techniques applied is to frac-pack the wells. The usual practice is to clean up the well as soon as possible to minimize formation damage. This process can take up to seven days, which results in frac fluid being left in the formation. This paper examines the effect of shut-in times following hydraulic fracturing treatments on the return permeability of the reservoir core. Lab studies included conducting coreflood experiments using reservoir cores and typical treatment fluids. The study was performed at bottomhole conditions (300°F) using cores with air permeabilities ranging from 25 mD to 28D. Polymer and breaker concentrations in the fracturing fluid were identical to those used in the field. Core plugs were tested by both methods: injecting and circulating the fracturing gel, and soaking it under pressure for up to seven days. Tests were performed in the absence and presence of a breaker, unencapsulated sodium bromate. Application: Guar gum and its derivatives are commonly used to prepare hydraulic fracturing fluids. During fracturing treatments, the polymer invades the formation and leaves a gel residue in the fracture and formation, which impairs well deliverability. Several factors like polymer loading, formation temperature, shut-in time and clean-up process contribute to the treatment outcome. A common belief (misconception) has been that long shut-in periods after fracturing a gas well will further reduce the permeability, and the impairment of delivery becomes severe. To avoid the resulting damage of the well, the treatment fluids are recovered while the rig on location, which costs rig time. This concept has led us to study the impact of shut-in time on the retained permeability of reservoir cores. Results, Observations, Conclusions: Experimental results reveal that 25% reduction in the permeability of reservoir cores occurs at a polymer loading of 45 lb/1,000 gals. A lower polymer loading of 35 lb/1000 gals caused less damage to the permeability. Most of the damage occurred during the first few hours of interaction of the gel with the core plug. Longer shut-in times did not cause additional damage. This study resulted in a significant cost savings by avoiding the need to flowback the well with the rig on location. Technical Contributions: Guar gum polymer used in hydraulic fracturing treatment can cause damage up to 25%. The damage occurred once the fracturing gel invades the formation. Longer shut-in times don't cause additional damage up to seven days. The degree of damage depends on the breaker concentration. Introduction Hydraulic fracturing technique is applied to create a conductive fracture in the pay zone to enhance well deliverability. A fracture is initiated by injecting a viscous fluid at a rate higher than the matrix can accept, based on Darcy's law. This will cause the formation to fracture in order to accommodate the high injection rates.1 The fracturing fluids are the most important components in hydraulic fracturing treatments. These fluids create fracture and transport the proppant, which in turn prevents the closure of the fracture after the treatment.2,3 Fracturing fluids should have sufficient viscosity to suspend and transport the proppant, should not damage the proppant pack or formation, should remain stable at reservoir pressure and temperature, exhibit low friction losses, having moderate efficiency, and should be resistant to shear degradation.3 After completion of the treatment, the gel must break down such that they can be removed from the formation. In a typical water-based fracturing fluid, high viscosity is generated by cross-linking polymer molecules (guar, HPG or CMHPG) with a multivalent cation like Ti(IV) and Zr(IV).4,5 In some cases, aluminum compounds are used for crosslinking.6 Cross-linking helps in achieving high viscosity necessary for fracturing without increasing polymer loading. Gels crosslinked with Ti and Zr ions have inherent problems of permeability reduction, fluid cleanup after treatment and damage to the proppant pack. This results in low fracture conductivity and poor well production.3

Hydraulic fracturing has been extensively used as an efficient method to enhance the hydrocarbon production, especially in tight formations. However, this technique has been associated with long-lasting formation damage challenge due to fracturing fluid filtrate leakoff. According to Laplace equation, this fluid leakoff results in a phenomenon called water blockage due to capillary forces. Recent studies have shown that surfactants can be used as an additive to fracturing fluids and they will reduce the required pressure to displace the injected fracturing fluids. In this study, the performance of two new nano-emulsion surfactants has been investigated. Nano-emulsion surfactant mixtures were prepared at different concentrations ranging from 0.5 to 5 gpt using field mixing water. Mixing water and representative field condensate samples were used to conduct both the surface tension and contact angle measurements at temperature range of 77-325°F. Laplace equation was used to calculate capillary pressure values based on surface tension and contact angle values. The results based on this study have illustrated the effectiveness of nano-emulsion surfactants to recover the fracturing fluid filtrate during flowback. The performance of these surfactants was investigated as a function of several parameters such as surfactant concentration, soaking time, and temperature. In addition, this paper explored the adsorption behavior of these surfactants on formation rock and the effect of nano-emulsion surfactants on the rock wettability. Optimal design parameters of these nano-emulsion surfactants to achieve significant enhancement in injected fracturing fluid recovery are also discussed.

Water production can reduce or block oil and gas production rates. In addition, the lifting, handling, and disposal of produced water negatively impact the hydrocarbon production economics. Among several techniques for water control, crosslinked polymer systems are the most effective for certain water shut-off projects. The objective of this paper is to assess the effectiveness of crosslinked polymer system for water control applications in carbonate formations and present its optimal formulation. This paper presents a detailed lab testing of a cross-linked polymer system. The system includes a gelling agent, primary and secondary crosslinkers and an acidic activator. The evaluation covered extreme concentrations of all components, temperatures up to 212°F, differential pressures up to 1,500 psi, actual field water salinity, wide range of permeability, and extended testing time up to three months. Core-flood experiments along with Computerized Tomography Scanning and Environmental Scanning Electron Microscopy were used to assess the sweep efficiency and the strength of the gel inside the core plugs. Losses of active ingredients from effluent samples were measured using Thermal Gravimetric Analyzer. Results of carbonate core plugs were compared with that of Berea sandstone. Strength of the gel at different cross-linker and polymer concentrations was monitored using sealed glass ampoules. Gelation times were measured using bottle tests and rotational viscometers. Extreme vertices design was used to optimize the experimental work and mixture triangle was used to represent the final results. An optimal gelling system with controlled gelation time and maximum performance was attained for the targeted formation at 212°F. It was found that the gelation time was affected by the three main components of the gelling system. The acetic acid-based activator was found to have the highest effect on the gelation time. However, this activator was not effective when the gelling system was tested in carbonate core plugs. A major effort of this work was to develop alternative strategies for the ineffectiveness of acidic activator in carbonaceous formations.

Water shutoff using polymer gels has been practiced with success for long time. However, in certain cases, there is a need to acidize a well while isolating part of it using a gel treatment especially in long horizontal wells. The application of combined treatment is challenging and has resulted in a mixed outcome. The acid reacts with carbonate around the gel destroying the benefits of the gel treatment. Likewise, the application of the gel post an acidizing treatment is ineffective. The objective of this paper is to investigate the effectiveness of combining water shut-off and acidizing in one treatment in carbonate formations. Core-flood testing was conducted to investigate the effectiveness of water shut-off gels before and after acidizing the core plug. Two scenarios were examined; the first one included pumping a cross-linked organic polymer gel to a carbonate core plug then followed by emulsified acid. In the second scenario, the core plug was acidized then the gel treatment was pumped. The gelling system consisted of polymer and dual set of delayed organic crosslinkers. The acid was 20 wt% emulsified HCl. CT scanning images were obtained before and after each step. The testing was performed at 200°F and 500 psi pore pressure. The core flood experiments showed that when acid was applied after the gel treatment wormholes were created and dissolved the rock around the gel. On other hand, when the gel was applied after the acid, the gel was not able to withstand the differential pressures and allowed the flow of water because of the inability of the gel to plug the wormholes. It was demonstrated that the gel and acid treatments must be isolated from each other by mechanical means or deeper penetration of the gel.