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Abstract Successful field trials of surfactant-based Production Enhancement (PROE) technology in different shale plays including Permian Basin, Bakken and Eagle Ford indicate that specially tailored surfactant formulations can improve the unconventional well productivity during flowback and production. One major challenge for the operator is to further optimize the surfactant dosage to maximize the economic return. Analysis of the residual surfactant concentration in the produced water (PW) might provide a new path to optimize the surfactant application in the field. Such quantitative measurements can help understand how much surfactant is consumed in the downhole and how much surfactant is in the flowback, and possibly correlate back to the well performance. Additionally, surfactant partitioning and adsorption behaviors can be studied through residual analysis, which will further provide guidance to develop next generation of surfactant formulations. In this study, a liquid chromatography-mass spectrometry (LC-MS) method was developed to accurately measure the residual surfactant concentration in the produced water. The liquid chromatograph (LC) separates the surfactant from sample matrix and avoids the possible interference, and then the mass spectrometer (MS) detects the separated surfactant, signal correlating to the residual concentration. This analytical method provides unrivalled selectivity and specificity compared to other methods reported in the literature. In addition, a Methyl Orange method was developed and can potentially be used in the field for quicker measurements. Produced water samples collected from a Huff-and-Puff treatment in the Permian Basin were evaluated using both methods. Our results indicate that both methods can successfully capture the trend of residual concentration vs. production time. The deviation between LC-MS and Methyl Orange measurements was due to the presence of ADBAC (alkyldimethylbenzylammonium chloride) in the produced water, which is a cationic amine surfactant typically used as biocide in the well stimulation. It produces positive interference and thus leads to a higher residual detection in the Methyl Orange test. Notably, the residual concentration of surfactant in produced water decreased with time after the well was placed back to production, which is consistent with the concept that more surfactant will adsorb to the rock surface or partition into the oil phase over production time. In summary, we believe the LC-MS and Methyl Orange methods can potentially be used to detect residual concentration for any type of surfactant-based applications in unconventional reservoirs including Huff-and-Puff, completion, frac protect, surfactant flooding and re-frac. The field application of surfactant-based chemistry followed by this type of residual analysis can help understand the underlying mechanisms of the surfactant and provide further guidance for production optimization of shales.
Abstract Hydraulic fracturing technology has grown popular with the rapidly increasing development of tight conventional and unconventional reservoirs. A major concern with this technique is the use of large amounts of water in these treatments. The use of water causes many potential damaging issues in the formation and limits the amount that can be saved for future generations. One solution is waterless fracturing treatments, which were developed to reduce or eliminate the need for water in hydraulic fracturing. Hydraulic fracturing treatments consume at least 200,000 gallons of water in conventional wells and up to 16,000,000 gallons of water in unconventional wells. The pumped water must include clay stabilizers to deal with the sensitive clays in the formation. Additionally, using water poses a risk of inorganic scale precipitation near the wellbore. Water can also cause severe emulsions that can lead to emulsion blockage cases. Moreover, there are significant reports of water blockage cases in tight gas wells. Only a mere 10-30% of pumped water flows back after the treatment, with the rest attached to clays, or stuck in the pores due to high capillary pressures. Water-based fluids can also cause alterations to relative permeability, and liquid holdup cases in many gas wells. These issues can certainly increase near wellbore skin and reduce production rates. At the end of the treatment, water still causes issues related to disposal and separation prior to diverting it to the plant. The main challenges in developing waterless fluids include feasibility, environmental friendliness, and effectiveness to stimulate the reservoir. This review will cover the various waterless fracturing methods such as hydrocarbon-based, liquid CO2, energized, and foamed fluids (CO2 and N2 foams) as well as their advantages and disadvantages. Studies into the properties of these fluids, such as rheology, solubility, compatibility, will also be discussed. Field trials will be examined where applicable. This literature review examines various waterless alternatives to traditional fluids for hydraulic fracturing. From this paper, readers can better understand the nature of waterless technologies and be able to better evaluate these technologies for fracturing purposes.
Abstract Injection of chemicals in enhanced oil recovery (cEOR) such as alkaline (A), surfactant (S), and polymer (P) can increase the oil recovery by changing the properties of the injected fluid to make better interaction with oil in the reservoir. In this work, micellar fluid interactions were studied via microemulsion rheological behavior using naphthenic crude oil and stimulated brine contains ASP. The influence of water cut (WC), temperature, salt concentration, shear, and viscoelastic properties were studied using a chemical cocktail consist of ASP and Naphthenic Acid (NAs) crude oil with a formulated biobased chemical that contained synthesized compound. The rheological properties, when added biobased formulation labeled as surfactant S53 and S57 in the ASP-crude oil system, resulted in a different viscosity — viscous-like behavior of emulsion and microemulsion in varying quantity of synthetic brine and temperature. At a specific volume of brine, both emulsion and microemulsion from S53 and S57 undergo a shear-thinning phenomenon where it behaves like a non-newtonian micellar fluid, as when viscosity decreases with the increase of shear rate. This thixotropy characteristic is suitable to be applied at the injection well in which high shear rate condition requires lower viscosity to assist in injectivity. The fluid when it flows into the reservoir, the viscosity increases sweep residual oil in pore and oil film in pore throats. Overall in this paper will describe the rheology and its microscopic behavior of emulsion and microemulsion generated on the addition of S53 and S57 surfactants in determining the condition of cEOR micellar fluids application.
Yang, Weipeng (University of Tulsa) | Fu, Chenliang (University of Tulsa) | Du, Yujing (University of Texas at Austin) | Xu, Ke (Peking University) | Balhoff, Matthew T. (University of Texas at Austin) | Weston, Javen (University of Tulsa) | Lu, Jun (University of Tulsa)
Summary Surfactant flooding is an effective enhanced oil recovery method in which the oil/water interfacial tension (IFT) is reduced to ultralow values (<0.01 mN/m). The microscopic fluid-fluid displacement has been extensively studied at high IFT (>10 mN/m). However, the microscopic displacement dynamics can be significantly different when the IFT is ultralow because the dynamic contact angle increases with the increase of the capillary number. In this study, surfactant flooding was performed and visualized in micromodels to investigate the dynamics of multiphase displacement at ultralow IFT. Although the micromodels used were strongly water-wet, the displacements of oil by surfactant solutions at ultralow IFT appeared as drainage. Furthermore, a macroscopic oil film was left behind on the surface, which indicates that a contact line instability occurred during displacements. The shape of the oil/water meniscus was determined by the balance between viscous forces and capillary forces. The meniscus can be significantly distorted by viscous forces at ultralow IFT. Therefore, the water-wet micromodel exhibits an oil-wet behavior at ultralow IFT, and the displacements of oil by surfactant solutions at ultralow IFT manifested as drainage rather than imbibition. The flow behavior is further complicated by the spontaneous formation of microemulsion during displacement. The microemulsion is mainly formed from the residual oil. The formation of a microemulsion bank made the surfactant solution discontinuous, with transport in the form of droplets in the microemulsion bank and displacement front. The novelty of this work is to reveal the effects of dynamic contact angle on the ultralow IFT displacement.
Ascorbic acid was used to synthesize crystalline starch nanoparticles (CSNP) for the first time. The CSNP was isolated and the influence of the process variables on the physical properties, recovery yield and crystallinity were studied. Rheology of crystalline starch nanofluid (CSNF) was compared with cassava starch (CS) solution and xanthan. Interfacial tension (IFT) of CSNF was studied at various concentration and temperatures. Influence of concentration, temperature, salinity and their interaction with ultrasound were investigated. Sessile drop contact angle method was used to determine the wettability proficiency of CSNF on an initially oil-wet sandstone core. To justify the finding highlighted above, CSNF and CS solution were applied for EOR purposes at reservoir condition. The approaches were efficient in generating sphere-shaped and elongated nanoparticles (50 nm mean diameter) and higher yield of 39%. Increase in concentration, surface area and temperature of CS and CSNF increased viscosity in comparison to decline in viscosity as the temperature increases for xanthan. Increased concentration, salinity and temperature rise of CSNF decreased IFT and altered the wettability of the sandstone core. CSNF increased the oil recovery by 23% and was effective at high temperature high pressure reservoir conditions. The energy consumption and cost estimation has demonstrated that the methods and polymeric nanofluid are cost-effective than traditional methods and products.
Beck, Griffin (Southwest Research Institute) | Bhagwat, Swanand (Southwest Research Institute) | Day, Carolyn (Southwest Research Institute) | Gordon, Emilio (Southwest Research Institute) | Daeffler, Chris (Schlumberger) | Malpani, Raj (Schlumberger) | Verma, Sandeep (Schlumberger) | Chaves, Leo (Chevron) | Comeaux, Bruce (Chevron) | Chrusch, Larry (Chevron) | Naik, Sarvesh (Chevron) | Renk, Joseph (National Energy Technology Laboratory)
Nitrogen (N2) and Carbon Dioxide (CO2) foams have been used as hydraulic fracturing fluids for several decades to reduce water usage and minimize damage in water-sensitive reservoirs. These foam treatments require gases to be liquefied and transported to site. An alternative approach would be to use natural gas (NG) that is readily available from nearby wells, pipelines, and processing facilities as the internal, gaseous phase to create a NG-based foam. Hydraulic fracturing with NG foam is a relatively inexpensive option, makes use of an abundant and often wasted resource, and may even provide production benefits in certain reservoirs. As part of an ongoing development project sponsored by the Department of Energy (DOE), the surface process to create NG foam is being developed and the properties of NG foam are being explored. This paper presents recent results from a rigorous pilot-scale demonstration of NG foam over a range of operating scenarios relevant to surface and bottomhole conditions with a variety of base-fluid mixtures.
The NG foams explored in these investigations exhibited typical, shear-thinning behavior observed in rheological studies of N2- and CO2-based foams. The measured viscosity and observed stability indicate that NG foams are well suited for fracturing applications. Like other foams, NG foam exhibits sensitivity to operating temperature characterized by a decrease in apparent viscosity as temperature increases. Rapid foam breakdown was observed at significantly elevated temperatures exceeding 290°F. In addition to fluid characterization, these investigations also yielded several key lessons that should be applied to future field demonstrations of NG foam.
Summary An experimental study was conducted to determine the influence of fluid elastic properties on the critical velocity, frictional pressure drops, and the turbulent-flow characteristics of polymer-fluid flow over a sand bed deposited in a horizontal pipe. Fluids were prepared using a special technique, which allowed for the alteration of fluid elastic properties while keeping the shear viscosity constant. By conducting experiments under controlled conditions, we were able to quantify the individual effect of the fluid elasticity (independent from shear viscosity) on the critical flow rate for bed erosion and the turbulent-flow characteristics of polymer-fluid flow over the stationary sand bed. Results showed that higher critical velocities were required for the onset of the bed erosion when we use the fluid with higher elasticity.
Summary Since the introduction of viscous/capillary concepts by Moore and Slobod (1956), several modifications and advancements have been made to the capillary number (Nc) so that it could have a better correlation with residual oil saturation (Sor) during enhanced oil recovery (EOR). In subsequent years, laboratory-scale studies have indicated that the viscoelastic polymers can influence the Sor reduction at relatively higher fluxes and Nc. Although the flux rate of at least 1 ft/D is reported to be needed for viscoelastic polymers to reduce Sor to a noticeable extent, significant Sor reductions were reported to occur only at higher fluxes that are likely to be seen in the reservoir closer to the wellbore. At similar levels of flux and Nc, the polymer solutions with significant elastic properties have shown higher Sor reduction than viscous polymer of similar shear rheology. However, the existing models used for correlating the polymer’s viscoelastic effect on Sor reduction relies on either core-scale Nc and/or the oscillatory Deborah number (De). De also has limitations in quantifying the polymer’s viscoelastic effects at different salinities. In this paper, a modified capillary number called an extensional capillary number (Nce) is developed using the localized pore-scale extensional viscosity. For viscoelastic polymer solutions, pore-scale apparent viscosity dominated by localized extensional viscosity is calculated to be significantly higher than core-scale apparent viscosity. We provide rheological insights using the variable-strain-rate concept to explain why and when the pore-scale apparent viscosity could become significantly higher, even at a flux of approximately 1 to 4 ft/D, and why it will not be reflected on the core-scale apparent viscosity or pressure drop. An exponential correlation was developed between Nce and Sor using the extensive coreflood experimental data sets extracted from various literature. Performance of Nce for predicting the viscoelastic polymer’s residual oil recovery is compared with conventional Nc, De, and a recent correlation. The results show that newly developed Nce can predict the Sor during polymer flooding for a wide range of operational and petrophysical conditions, including brine-salinity effects.
Abstract To minimize fluid loss and the associated formation damage, underbalanced coiled tubing (CT) is one of the preferred methods to perform cleanout operations and re-establish communication with an open completion interval. Because of their high viscosity and structure, stable foams are suitable cleanout fluid when underbalanced CT operations are applied. However, unstable foams do not possess high viscosity and as a result, they are poor in cleanout operations, especially in inclined wellbores. This study is aimed to investigate the effects of wellbore inclination on the stability of foams. In this study, foam drainage experiments were carried out using a flow loop that has foam drainage measurement section and pipe viscometers. To verify proper foam generation and validate the accuracy of measurements, foam rheology was measured using pipe viscometers. Drainage experiments were performed with aqueous, polymer-based, and oil-based foams in concentric annulus and pipe under pressurized conditions. Tests were also conducted at an inclined orientation to examine the effect of wellbore inclination on the stability of foams. The foam bubble structure was examined and monitored in real-time using a microscopic camera to study bubble coarsening. The foam quality (i.e. gas volume fraction) was varied from 40 to 80%. The drainage rate was slightly higher in the pipe section than in the annulus. More importantly, the drainage rate of foam in an inclined configuration was significantly higher than that observed in a vertical orientation. The inclination exacerbated foam drainage and instability substantially. The mechanisms of foam drainage are different in inclined configuration. In inclined wellbores, drainage occurs not only axially but also laterally. As a result, the drained liquid quickly reaches a wellbore wall before reaching the bottom of the hole. Then, a layer of liquid forms on the low-side of the wellbore. The liquid layer flows downward due to gravity and reaches the bottom of the hole without facing major hydraulic resistance of the foam network. This phenomenon enhances the drainage process considerably. Although foam drainage experiments are reported in published literature, there is limited information on the effects of geometry and inclination on foam drainage and stability. The information provided in this article helps to account for the impact of inclination on foam stability to improve its CT cleanout performance in directional wells.