Fracturing fluids are commonly formulated with fresh water to ensure reliable rheology. However, fresh water is becoming more costly, and in some areas, it is difficult to obtain. Therefore, using produced water in hydraulic fracturing has received increased attention in the last few years. A major challenge, however, is its high total dissolved solids (TDS) content, which could cause formation damage and negatively affect fracturing fluid rheology. The objective of this study is to investigate the feasibility of using produced water to formulate crosslinked-gel-based fracturing fluid. This paper focuses on the compatibility of water with the fracturing fluid system and the effect of salts on the fluid rheology.
Produced water samples were analyzed to determine different ion concentrations. Solutions of synthetic water with different amounts of salts were prepared. The fracturing fluid system consisted of natural guar polymer, borate-based crosslinker, biocide, surfactant, clay controller, scale inhibitor, and pH buffer. Compatibility tests of the fluid system were conducted at different cation concentrations. Apparent viscosity of the fracturing fluid was measured using a high-pressure high-temperature rotational rheometer. All rheology tests were conducted at a temperature of 180°F and were conducted according to API 13m procedure with a three-hour test duration. Fluid breaking test was also performed to ensure high fracture and proppant pack conductivity.
Produced water analysis showed a TDS content of 125,000 ppm, including Na, Ca, K, and Mg ion concentrations of 36,000, 10,500, 1,700, and 700 ppm, respectively. Results indicated the potential of produced water to cause formation damage. Therefore, produced water was diluted with fresh water and directly used to formulate the fracturing fluid. Divalent cations were found to be the main source of precipitation, and the reduced amounts of each ion were determined to prevent precipitation. The separate and combined effects of Na, K, Ca, and Mg ions on the viscosity of the fracturing fluid were also studied. Fluid viscosity was found to be significantly affected by the concentrations of divalent cations regardless of the concentrations of monovalent cations. Monovalent cations reduced the viscosity of fracturing fluid only in the absence of divalent cations, and showed no effect in the presence of Ca and Mg ions. Water with reduced concentrations of monovalent and divalent cations showed the most suitable environment for polymer hydration and crosslinking.
This paper contributes to the understanding of the main factors that enable the use of produced water for hydraulic fracturing operations. Maximizing the use of produced water could reduce its disposal costs, mitigate environmental impacts, and solve fresh water acquisition challenges.
Polymer transport and preparation can present a key challenge in chemical EOR project implementation.
Hydrolyzed polyacrylamide in emulsion form presents some advantages, including an easier transportation and a simplification of the injection process. The trade off is a lower active concentration (~30% - 50%), which increases the volumes to be transported, as well as the presence of oil and emulsifiers, which may have unintended effects in the reservoir.
In this article, we compare two industrial and commercially-available polymers, one in powder form from the gel process, and the other in an inverse emulsion, with similar viscosifying power.
Properties of both polymers are investigated through rheological and screen factor measurements, filterability tests on bulk solutions, shear thickening behavior and resistance to shear degradation in porous medium. The likely origin of the observed differences is discussed in light of the two polymerization methods (bulk vs. emulsion) that lead to differences in polydispersity. Mobility reduction and residual resistance factor measurements during propagation tests at low velocity give some insight on the propagation of the stabilized oil droplets coming from the injected emulsion. Finally, oil recovery efficiency is investigated through secondary polymer injections on sandpacks. No significant difference was observed between the polymers in term of oil recovery or pressure behavior.
These results are relevant to oil companies planning polymer or surfactant-polymer pilots and considering the tradeoffs between emulsion and powder polymers.
Polymer flooding is a proven technology to improve sweep efficiency, while being one of the most economical enhanced oil recovery (EOR) processes. Partially hydrolyzed polyacrylamide (HPAM) has been widely used for polymer flooding. As the HPAM usage for EOR increases, the challenge of produced water management is also raised because residual HPAM in produced water could increase total chemical oxygen demand and unwanted viscosity in discharging or re-injecting the water. As the environmental standards and regulations get more stringent, it is difficult for the conventional methods to meet the requirement for discharging. Use of magnetic nanoparticles (MNPs) to remove contaminants from produced water is a promising way to treat produced water in an environmentally green way with minimal use of chemicals. The main attraction for MNPs is their quick response to move in a desired direction with application of external magnetic field. Another attraction of MNPs is versatile and efficient surface modification through suitable polymer coating, depending on the characteristics of target contaminants. In this study, we investigate the feasibility of polymer removal using surface-modified MNPs and regeneration of spent MNPs for multiple re-use.
The electrostatic attraction between negatively charged HPAM polymer and positively charged MNPs controls the attachment of MNPs to HPAM molecular chain; and the subsequent aggregation of the now neutralized MNP-attached HPAM plays a critical role for accelerated and efficient magnetic separation.
Qiu, Yue (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Geng, Jiaming (Missouri University of Science and Technology) | Wu, Fengxiang (Daqing Xinwantong Chemical Co. Ltd.)
This paper presents the detailed descriptions of successful field application for a high-temperature and high-salinity resistance microgel in a mature reservoir in the northwest part of China. The reservoir with low permeability (230 md) experienced serious vertical and lateral heterogeneity problems, which caused low sweep efficiency and high water-cut (more than 95%). The treatment was designed based on laboratory experiments and experience from previous field application, providing detailed information of mechanism of microgel treatment and project execution. Thermal stability test showed that the microgel could resist the salt concentration up to 230,000 ppm at 125 °C for more than 1 year. From the core analysis, permeability of the long-term water-flooded zone was measured around 1,489 md, proving the evidence that high-permeability zones existed. Pilot test has been done before field application and valuable experience about how to design the injection parameters was provided. According to the information from laboratory experiments and the pilot test, four injection wells associated with nine offset production wells were selected for microgel treatment. For about 10 months treatment, 169 t of microgel was injected by five slugs.
Gradually increased injection pressure suggested that microgel could be placed deeply into the reservoir. The ultimate incremental oil production was approximately 29,635.8 t with the water cut decreasing from 95.3% to 93.1%. Microgel can be successfully used in relative low permeability (230 md) reservoir with harsh conditions for conformance control.
Griffith, Nicholas (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Ahmad, Yusra (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Daigle, Hugh (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Huh, Chun (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin)
Interest in silica nanoparticle-stabilized emulsions, especially those employing low-cost natural gas liquids (NGLs), has increased due to recent developments suggesting their use leads to improved conformance control and increased sweep efficiencies. When compared to conventional emulsion- stabilizing materials such as surfactants, nanoparticles are an inexpensive and robust alternative, offering stability over a wider range of temperature and salinity, while reducing environmental impact.
Oil-in-water emulsions with an aqueous nanoparticle phase and either a pentane or butane oil phase at a 1:1 volume ratio were generated at varying salinities for the observations of several emulsion characteristics. The effects of salinity on the stability of silica nanoparticle dispersions and NGL emulsions were observed. Increasing the salinity of the aqueous nanoparticle phase resulted in an increase in effective nanoparticle size due to increased nanoparticle aggregation. Rheology tests and estimates of emulsion droplet sizes were performed. Shear-thinning behavior was observed for all emulsions. Furthermore, overall emulsion viscosity increased with salinity. Nanoparticle-stabilized liquid butane-in-water emulsions were also generated with varying brine concentrations; however, no rheology or droplet size measurements were made due to the volatility of these emulsions.
Residual oil recovery coreflood experiments were conducted (using Boise Sandstone cores) with nanoparticle-stabilized pentane-in-water emulsions as injectant and light mineral oil as residual oil. A recovery of up to 82% residual oil was observed for these experiments. By continuously measuring the pressure drop across the core, a possible mechanism for enhanced oil recovery is proposed. Pentane emulsion coreflood tests indicated that at a slower injection rate, residual oil recovery increases. This contrasts viscous emulsion corefloods (mineral oil or Texaco white oil as the emulsion oil phase), where increasing the injection rate increases the residual oil recovery.
Jang, Sung Hyun (The University of Texas at Austin) | Liyanage, Pathma Jith (The University of Texas at Austin) | Tagavifar, Mohsen (The University of Texas at Austin) | Chang, Leonard (The University of Texas at Austin) | Upamali, Karasinghe A. N. (The University of Texas at Austin) | Lansakara-P, Dharmika (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
The chemical cost to recover an incremental barrel of oil is directly proportional to the surfactant retention, so the single most effective way to reduce the cost is to reduce surfactant retention. The main objective of this research was to demonstrate how surfactant retention could be reduced to almost zero by careful optimization of the chemical formulations for different crude oils. Although surfactant retention has been studied for many years over a wide range of reservoir conditions, its dependence on the rheological behavior of the microemulsion that forms in-situ has not been adequately studied. Thus, in this paper we emphasize the importance of microemulsion rheology and demonstrate how to develop and test formulations with properties that give very low surfactant retention. Novel co-solvents (iso-butanol (IBA) alkoxylates and phenol alkoxylates) were tested in some of the formulations with excellent results. Unlike classical co-solvents used to optimize chemical formulations, the new co-solvents cause only a slight increase in the interfacial tension. A series of ASP corefloods were performed in sandstone cores with and without oil to measure surfactant and co-solvent retention and to elucidate the effects of microemulsion viscosity, salinity gradient, clay content, surfactant concentration and other variables. Dynamic adsorption was measured in cores with the same mineralogy and compared with the retention from oil recovery corefloods to determine the component of the retention due to phase trapping.
Tagavifar, Mohsen (The University of Texas at Austin) | Herath, Sumudu (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin) | Pope, Gary (The University of Texas at Austin)
We made measurements of microemulsion rheology with mixtures of oil, brine, surfactant, co-solvent, and in some cases polymer to systematically investigate the effects of salinity, co-solvents and polymers. A microemulsion rheology model was developed and used to interpret the experimental results. We show that the optimum microemulsion-to-oil viscosity ratio is roughly 5 to 6 without co-solvent, but it can be reduced to a more favorable ratio of ~2 by adding co-solvent. Even though the amount of co-solvent needed is case dependent, a clear trend of microemulsion viscosity reduction with increasing co-solvent concentration was observed. Limited evidence suggests that large hydrolyzed polyacrylamide molecules with a narrow molecular weight distribution have negligible partitioning to type II and III microemulsions.
Post-fracturing production data analysis indicates stimulation of some west Texas wells with surfactant additives did not enhance production as high as expected. Analysis of flowback and produced water for surfactant residues revealed 99% of surfactant was retained inside wells (
Literature precedent exists that polyelectrolyte (PET)-based SAs could significantly reduce surfactant adsorption not only onto a variety of outcrop minerals (Carlpool dolomite, calcite, kaolinite, Berea sandstone, Indiana limestone, etc.) and metal oxide nanoparticles, but also unconventional shale formulations in which surface area can be up to 700 m2/g. In this study, the adsorptions of surfactant and SA to proppants were first examined. Results indicate no adsorption was observed to proppant for both surfactants and PET-based SAs. SAs (0.5 to 1 gal/1,000 gal (gpt)) were then injected with surfactant (1 to 3 gpt) at an appropriate ratio into column-packed shale formulations (primarily composed of calcite, dolomite, quartz, illite, pyrite, and plagioclase feldspar) to investigate its effectiveness in controlling surfactant retention caused by adsorption. Laboratory testing revealed injection of 3 gpt mixture of surfactant and SA has a similar adsorption profile (surface tension as a function of time) as 3 gpt surfactant alone based on the dynamic surface tension measurement. Notably, the addition of SAs resulted in lower surface tension and enhanced hydrocarbon solubility; and thus, an improved oil recovery by surfactant was achieved as evidenced by the oil recovery tests. Additionally, 68% friction reduction of the fracturing fluid with surfactant and SA was sufficient for the field operation compared to the guar-based fluid used in the hydraulic fracturing applications.
As a result of the laboratory findings, field trials were executed on a three well pad in the Permian basin (PB). For the first 30 days oil and gas production appeared to be significantly higher than the average production from offset wells in the same area that were previously fractured with the same surfactant.
Jin, Luchao (University of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Jamili, Ahmad (University of Oklahoma) | Li, Zhitao (The University of Texas at Austin) | Luo, Haishan (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Shiau, Ben (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
The surfactant screening process to develop an optimum formulation under reservoir conditions is typically time consuming and expensive. Theories and correlations like HLB, R-ratio and packing parameters have been developed. But none of them can quantitatively consider both the effect of oil type, salinity, hardness and temperature, and model microemulsion phase behavior.
This paper uses the physics based Hydrophilic Lipophilic Difference (HLD) Net Average Curvature (NAC) model, and comprehensively demonstrated its capabilities in predicting the optimum formulation and microemulsion phase behavior based on the ambient conditions and surfactant structures. By using HLD equation and quantitatively characterized parameters, four optimum surfactant formulations are designed for target reservoir with high accuracy compared to experimental results. The microemulsion phase behavior is further predicted, and well matched the measured equilibrium interfacial tension. Its predictability is then reinforced by comparing to the empirical Hand's rule phase behavior model. Surfactant flooding sandpack laboratory tests are also interpreted by UTCHEM chemical flooding simulator coupled with the HLD-NAC phase behavior model.
The results indicate the significance of HLD-NAC equation of state in not only shorten the surfactant screening processes for formulators, but also predicting microemulsion phase behavior based on surfactant structure. A compositional reservoir simulator with such an equation of state will increase its predictability and hence help with the design of surfactant formulation.
The production and transportation of heavy and extra-heavy crude oil are two of the paramount concerns in the oil industry due to the difficulties associated with heavy crude oil high viscosity. One of the most efficient techniques to improve the recovery and the transportability of such oil is to reduce its viscosity through dilution that can be applied solely or via thermal methods.
In the present work, a new type of plant-based diluent is proposed, and its efficacy in heavy oil viscosity reduction for different concentrations, temperatures and shear rates is studied. Various concentrations of diluent, ranging from 5 to 25 wt%, are added to heavy-oil samples with different concentrations of asphaltene and viscosity, ranging from 48000 to 65000 cp in ambient temperature. A rotational viscometer was then employed to the measure viscosity of the prepared samples at the temperature range of 70 to 190°F and a shear rate of 3 to 50 s-1.
The application of the proposed diluent led to promising results in that in caused the viscosity of the heavy oil samples to reduce by 93% in 75°F and 85% in 190°F with 20 wt% of diluent. To compare the performance of the proposed solvent and the common viscosity-reducing solvents, heavy oil samples were diluted with xylene and toluene with the same concentrations. Results indicated that the application of proposed diluent outperformed all of the commonly used solvents in terms of decreasing viscosity. The application of 20 wt% of the proposed diluent led to a 93% viscosity reduction of the heavy oil samples, which is 15% more than efficiency of adding the same concentration of toluene.
The proposed diluent is a plant-based, non-hazardous substitute to the conventional hazardous diluents, e.g., xylene or toluene, that provides more efficient viscosity reduction compared to its conventional alternatives. Its flashpoint is higher than that of light crude resulting in less evaporation at high temperatures thus a longer period of reduced viscosity can be obtained. Furthermore, due to its high flashpoint, the proposed diluent can be employed in thermal methods more efficiently.