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Gawas K.,Multi Chemical | Karami H.,University of Tulsa | Pereyra E.,University of Tulsa | Al-Sarkhi A.,King Fahd University of Petroleum and Minerals | Sarica C.,University of Tulsa
International Journal of Multiphase Flow | Year: 2014

An experimental study on wave characteristic has been carried out utilizing oil and air in a 0.1524. m ID horizontal and slightly inclined (±2°) pipe. A two-wire capacitance probe was developed to measure wave characteristics at the gas-liquid interface for two-phase flow in pipe. Wave celerity, amplitude and frequency have been determined from the capacitance time traces. The wave celerity increases with increase in superficial gas and liquid velocities. Although wave celerity was found to be dependent on inclination, the effect of inclination tends to diminish with increase in gas velocity. Wave amplitude and frequency did not show a particular trend for conditions studied. A new correlation for wave celerity for two-phase stratified flow using low viscosity fluids is proposed. The correlation was also compared with model prediction for wave celerity using mechanistic model proposed by others. © 2014 Elsevier Ltd.


He K.,Multi Chemical | Xu L.,Multi Chemical | Gao Y.,Colorado School of Mines | Neeves K.B.,Colorado School of Mines | And 4 more authors.
Proceedings - SPE Symposium on Improved Oil Recovery | Year: 2014

For liquids-rich shale plays, surfactants have proven to be a critical component in hydraulic fracturing fluid systems for enabling enhanced oil and gas recovery. The industry's most commonly used surfactant is a non-emulsifying surfactant (NES), but it has been previously demonstrated that a weakly emulsifying surfactant (WES) appears to be more efficient at mobilizing oil through tight pore throats. In this study, fundamental differences between those two surfactant types were further demonstrated using a Reservoir-on-a-Chip (ROC) approach, which allows direct visualization of oil recovery with the various surfactant fluids, allowing for the testing on both homogenous and heterogeneous pore structures with various geometries. The laboratory testing showed that, compared to a non-surfactant-bearing control fluid and the NES, the WES showed higher oil recovery efficiency at equal driving pressure. As a result of the laboratory testing indications, a multiple well trial program was conducted in two separate areas of the Eagle Ford shale. Production data from the wells stimulated using a WES-bearing fracturing fluid were normalized in terms of lateral lengths and fracturing stages, and compared to the offset wells stimulated using a NES-bearing fracturing fluid. Early production results suggest that wells treated with the WES exhibited enhanced productivity compared to those treated with the NES. Copyright 2014, Society of Petroleum Engineers.


He K.,Multi Chemical | Xu L.,Multi Chemical | Gao Y.,Colorado School of Mines | Yin X.,Colorado School of Mines | Neeves K.B.,Colorado School of Mines
Journal of Petroleum Science and Engineering | Year: 2015

Proper application of surfactants during hydraulic fracturing operations not only enhances initial production of a reservoir, but also helps sustain its long-term production. The most commonly used surfactant for low-permeability reservoirs is a non-emulsifying surfactant (NES). This study shows that a weakly emulsifying surfactant (WES) is better in solubilizing oil globules via self-association, and appears to be more efficient at mobilizing oil through tight pore throats than NES. The fundamental difference between these two surfactant types was found to be the emulsion tendency. The performance of the two surfactants was compared using a microfluidic based Rock-on-a-Chip (ROC) device with pore sizes comparable to shale formation rocks. The ROC allowed direct visualization of oil recovery by surfactants with controlled pore geometries and surface chemistry. Results showed that the WES yielded higher oil recovery efficiency at equal driving pressure compared to a non-surfactant-bearing control fluid and the NES. As a result of the laboratory testing indications, a multiple well trial program was conducted in two separate areas of the Eagle Ford shale. Early production results suggest that wells treated with the WES exhibited enhanced productivity compared to those treated with the NES. © 2015 Elsevier B.V.


Xu L.,Multi Chemical | He K.,Multi Chemical | Rane J.P.,Multi Chemical | Yin X.,Colorado School of Mines | Neeves K.,Colorado School of Mines
Society of Petroleum Engineers - SPE Liquids-Rich Basins Conference - North America, LRBC 2015 | Year: 2015

For liquids-rich shale plays, a primary completion strategy is to enhance flow conductivity near the wellbore region by placing large-mesh proppant inside the fractures. One potential drawback of doing so is that the created fractures could be more planar in nature because of softer and more ductile rocks and therefore less contact could occur between fractures and the matrix during pumping. In addition, no external hydraulic force exists to drive fracturing fluids farther into the matrix after pumping is stopped at the surface. As a result, wells completed using this method could potentially suffer from a low fluid penetration rate into the reservoirs because of the resistance of capillary forces imparted by oil-wet or mixed-wet pores, which could result in lower-than-expected liquid production. In this study, a new mechanism is proposed for increasing the contact area between fracturing fluids and the matrix. The working hypothesis is that a surfactant, when properly tailored to treatment fluids, can help achieve this objective by spontaneously spreading in the matrix, thereby accessing additional hydrocarbon reserves. To investigate this hypothesis, two primary experimental techniques were used. • Fluid penetration depth into mixed-wet formation core plugs was monitored using computerassisted tomography imaging. Scans indicated that the fluid containing surfactants tends to penetrate almost twice as deep as that without surfactant. This observation is consistent with the finding of an earlier microfluidic study [1] that the use of surfactant significantly improved the rate of penetration of the non-wetting phase (water and surfactant solution) and the displacement efficiency of the wetting phase (oil). • The addition of surfactant reduced the interfacial surface tension, both elastic and viscous moduli (by means of the pulsating pendant drop method) of the oil-water interface to close to zero, making it deformable in the emulsion, which significantly aids oil mobilization. The study results imply that the shut-in time immediately after fracturing could be crucial for enhanced well productivity. An extended shut-in time could result in farther penetration of fracturing fluids into the matrix and lead to greater oil recovery in liquids-rich shale plays. Copyright 2015, Society of Petroleum Engineers.


Rane J.P.,Multi Chemical | Xu L.,Multi Chemical
SPE Production and Operations | Year: 2015

Surfactant is a significant component within fracturing-fluid additives that is used for enhancing oil and gas production following stimulation of unconventional reservoirs. To help ensure optimal applications of surfactants, operating and service companies have been searching for tools for tracking surfactant residuals in flowback and produced waters, which possibly can be correlated with well productivity. This paper discusses the residual surfactant concentration measured in produced water from example Barnett shale formation wells by use of a dynamic surface tension (DST) technique, which yields much more accurate measurements. DST measurement by maximum bubble-pressure technique is wellknown, but it has not been used explicitly for the application of residual surfactant measurement in produced water. A comparison of DST includes evaluating the diffusion coefficient to the reaction kinetics of adsorption of a known molecule(s) in produced water. Short-time kinetics of adsorption of different molecules vary on the basis of chemical nature and molecular size. Ultraviolet-visible (UV-Vis) spectroscopy is used to confirm the results. An estimate of residual concentrations from UV-Vis appears to be coherent with DST-measurement values. Such measurements can be useful in determining the surfactant concentration during pumping and the surfactant performance during and after hydraulic-fracturing operations. Additionally, these measurements serve a vital role in tailoring the surfactant additive to specific reservoir conditions to achieve higher oil recovery. Real-time production results from these different wells are analyzed and appear dependent on the corresponding residual surfactant concentrations from produced waters. This unique technique is new to the authors' knowledge for its use to study and analyze produced water for surfactant-additive concentration. Copyright © 2015 Society of Petroleum Engineers.


For low-permeability gas reservoirs, surfactants are typically added into fracturing cocktails to lower the capillary pressure in the pore spaces to enable a faster return of fracturing water to the surface, thereby providing additional surface area for gas flow Capillary pressure inside pore spaces, however, is not straightforward to predict or correlated to the performance of the surfactant that is to be used during fracturing. In this paper, a laboratory approach is presented for comparing surfactant performance by using the Washburn method for surfactant imbibition in crushed core particles from various unconventional formations, such as the Marcellus formation. Through analysis of the initial slopes of the imbibition curves over time at different salinities, it is possible to predict which surfactant would more effectively lower capillary pressure. In addition, gas production is often accompanied by condensate, which can accumulate in the near-wellbore (NWB) region, causing poor inflow performance. To overcome this issue, a transient or short-lived condensate-in-water emulsion is likely required to mobilize condensate more efficiently. Performing emulsion tendency analysis assisted with visual inspection demonstrated that weakly emulsifying surfactants are likely a better choice than typical field standard non-emulsifying surfactants. Production data from the Barnett formation are presented to validate the performance of the surfactant selected from imbibition and emulsion tendency analysis. Copyright 2013, Society of Petroleum Engineers.


Corrin E.,Multi Chemical | Rodriguez C.,Multi Chemical | Williams T.M.,Dow Chemical Company
NACE - International Corrosion Conference Series | Year: 2015

The recovery of petroleum resources from previously untapped shale reserves significantly impacts the global energy market. Effective management of limited water resources and control of microbial contamination in all process fluids are crucial to the sustained quality of production fluids. Microbiological contamination in untreated waters is recognized in the oil and gas industry as posing a high risk of production fluid souring by allowing the growth and metabolism of sulfate reducers. In addition to hydraulic source water contamination, it is expected that microbes can be introduced into shales at the time of drilling, necessitating the treatment of source waters to target existing downhole contamination. A two-part biocide treatment strategy has been extensively evaluated in controlled laboratory studies. The synergistic combination treatment involves the co-injection of dimethyl oxazolidine (DMO), along with the industry benchmark glutaraldehyde (GLUT). Laboratory testing showed a combination of treatments applied at 1:1 to 1:4 GLUT to DMO active ratios were highly synergistic against bacteria. This ratio provided a rapid kill of sulfate-reducing bacteria (SRB) and acid-producing bacteria (APB), as well as extended control in downhole conditions. Testing conditions were designed to simulate downhole conditions in a North American shale play; subsequently, the shale play was selected for field trials. A field-wide application of GLUT:DMO in the Niobrara formation was performed from 2012 to 2013. This case study reports 70 hydraulically fractured wells comprised from 25 well pads that received the GLUT/DMO combination treatment. The treatment was successful in maintaining low bacteria counts in the flowback/produced water, using liquid culture media (three positive SRB vials or less). Key advantages of this new treatment strategy include lower total biocide usage versus competitive biocides, an improved environmental (ecotoxicity) profile, enhanced performance at an alkaline pH, and compatibility with process additives. © 2015 by Nace International.


Xu L.,Multi Chemical | Fu Q.,Multi Chemical
Society of Petroleum Engineers - SPE Middle East Unconventional Gas Conference and Exhibition 2012, UGAS - Unlocking Unconventional Gas: New Energy in the Middle East | Year: 2012

A typical assumption for promoting the use of surfactants is that traditional surfactants will work appropriately across a large gamut of fields, but our laboratory tests show that inappropriate application leads to much lower efficiency of the oil recovery and thereby diminished production. Operators must understand how surfactants extract the oil and then select surfactants cautiously in order to maximize recovery and minimize risk. This paper presents a study on surfactant chemicals and their most relevant parameters. In particular, the key characteristic of surfactant additives in unconventional oil and gas formations was found to be the emulsion tendency. It was found that a weakly emulsifying surfactant was more capable of solubilizing and mobilizing additional oil globules via self association. In stark constrast to a conventional non-emulsifying surfactant, the correct application of a weakly emulsifying surfactant led to better well cleanup and a higher ultimate oil recovery. Copyright 2012, Society of Petroleum Engineers.

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