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von Gunten, Konstantin (University of Alberta) | Snihur, Katherine N. (University of Alberta) | McKay, Ryan T. (University of Alberta) | Serpe, Michael (University of Alberta) | Kenney, Janice P. L. (MacEwan University) | Alessi, Daniel S. (University of Alberta)
Summary Partially hydrolyzed polyacrylamide (PHPA) friction reducer was investigated in produced water from hydraulically fractured wells in the Duvernay and Montney Formations of western Canada. Produced water from systems that used nonencapsulated breaker had little residual solids (<0.3 g/L) and high degrees of hydrolysis, as shown by Fourier-transform infrared (FTIR) spectroscopy. Where an encapsulated breaker was used, more colloidal solids (1.1–2.2 g/L) were found with lower degrees of hydrolysis. In this system, the molecular weight (MW) of polymers was investigated, which decreased to <2% of the original weight within 1 hour of flowback. This was accompanied by slow hydrolysis and an increase in methine over methylene groups. Increased polymer-fragment concentrations were found to be correlated with a higher abundance of metal-carrying colloidal phases. This can lead to problems such as higher heavy-metal mobility in the case of produced-water spills and can cause membrane fouling during produced-water recycling and reuse.
Al-Muntasheri, Ghaithan A. (Saudi Aramco) | Li, Leiming (Aramco Services Company: Aramco Research Center–Houston) | Liang, Feng (Aramco Services Company: Aramco Research Center–Houston) | Gomaa, Ahmed M. (Saudi Aramco)
Summary Fracturing fluids are used for transport and placement of proppants in hydraulic-fracturing operations. In the case of conventional reservoirs, sufficient fluid viscosity is needed to transport proppant. An ideal fracturing fluid should possess enough viscosity to suspend and carry proppant. After the proppant placement, the fluid viscosity should drop to facilitate an efficient and quick fracture cleanup. This ensures adequate fracture conductivity. Most of the fracturing fluids used in these operations are dependent on crosslinking reactions between polymers and crosslinkers. Breaker technologies such as oxidizers, enzymes, fluoride compounds, oxides, vitamins, and decrosslinking agents are used to break the crosslinked polymer-based gels. These materials are added as components of the initial fracturing-fluids recipe. This paper will focus on the available breaker technologies used for degrading and cleaning up fracturing fluids used for conventional reservoirs. Each breaker has its own operating mechanism and window of application in terms of temperature and pH. The design and selection of a breaker package will first require an understanding of how the fracturing fluid forms. The current review reveals the crosslinking mechanisms of various fracturing fluids. These include the crosslinking of biopolymers with borates, the crosslinking of synthetic and biopolymers with metals, and the crosslinking of phosphate esters with metals. In the acidizing of carbonate reservoirs, the use of viscous fluids is needed to allow diversion of acid to lower-permeability paths. Moreover, the high viscosity retards the reaction between the acid and the rock, and this ensures deep penetration of the stimulation fluid. In this application, the viscosity develops as a response to the change in pH. Hydrocarbon fluids are used for hydraulically fracturing water-sensitive formations. Each of the aforementioned fracturing fluids has its own suitable breaker technology. For borate-crosslinked biopolymer gels, breakers such as oxidative and enzyme breakers can be used to reduce fluid viscosity by degrading polymer chains. An alternative approach to reduce viscosity of this type of fluid is the use of acids that lower the pH and decrosslink the fluid. A third route to reduce this fluid viscosity is by use of chelating agents and complexing agents. Lowering fluid viscosity alone may not sufficiently guarantee adequate proppant-pack and formation cleanup. It has been proved that low-viscosity fluids may still contain high-molecular-weight (MW) polymers that could severely damage formation and proppant pack. These high-MW polymers should be further broken into low-MW fragments with oxidizers or enzymes to achieve better production numbers. When metals are used to crosslink biopolymers and synthetic polymers, breakers such as oxidative breakers can still be effective. Acid fracturing fluids use fluoride-based breakers that can complex with the zirconium (Zr) and hence decrosslink the gel. When fracturing high-temperature wells, breakers can prematurely degrade the gel viscosity. This leads to less proppant placement and possibly screens out the proppant. As a result, the propped fracture becomes shorter and the well productivity will be less. To avoid this, breakers are encapsulated with materials that act as barriers between the breaker and fluid. The dissolution of the encapsulating material gives additional time for the gel to place the proppant. This paper reviews more than 100 papers and patents to summarize the experience and available knowledge in the area of using breakers for cleaning up fracturing fluids.
Beteta, Alan (Heriot-Watt University) | Nurmi, Leena (Kemira Oyj) | Rosati, Louis (Kemira Chemicals Inc.) | Hanski, Sirkku (Kemira Oyj) | McIver, Katherine (Heriot-Watt University) | Sorbie, Ken (Heriot-Watt University) | Toivonen, Susanna (Kemira Oyj)
Summary Polymer flooding is a mature enhanced oil recovery (EOR) technology that has seen increasing interest over the past decade. Copolymers of acrylamide (AMD) and acrylic acid (AA) have been the most prominent chemicals to be applied, whereas sulfonated polymers containing 2-acrylamido-tertiary-butyl sulfonic acid (ATBS) have been used for higher temperature and/or salinity conditions. The objective of this study was to generate guidelines to aid in the selection of appropriate polyacrylamide chemistry for each field case. Our focus was in sandstone fields operating at the upper end of AA-AMD temperature tolerance, where there is a decision as to whether sulfonation is required. The performance of the polymer throughout the whole residence time in the reservoir was considered because the macromolecule can undergo some changes over this period. Several key properties of nine distinct polymer species were investigated. The polymers consisted of AA-AMD copolymers, AMD-ATBS copolymers, and AMD-AA-ATBS terpolymers (up to 15 mol% ATBS). The polymer solutions were studied both in their original state as they would be during the injection (initial viscosity, initial adsorption, and in-situ rheology), as well as in the state in which they are expected to be after the polymer has aged in the reservoir (i.e., in a different state of hydrolysis with corresponding changes in viscosity retention and adsorption after aging for various time periods). We note that the combination of viscosity retention and adsorption during the in-situ aging process has not been typically investigated in previous literature, and this is a key novel feature of this work. Each of the above parameters has an impact on the effectiveness and the economic efficiency of a polymer flooding project. The majority of the work was carried out in seawater (SW) at a temperature of 58°C. Under these conditions, AMD-AA samples showed similar solution viscosity at 5 to 30% AA. When the AA-AMD polymer solutions were aged at elevated temperature, the AA content steadily increased because of hydrolysis reactions. When the AA content was 30 mol% or higher, the viscosity started to decrease, and the adsorption started to increase as the polymer solution was aged further. Thermal stability improved when ATBS was included in the polymer structure. In addition, sulfonated polyacrylamide samples showed constant initial viscosity yields and decreasing initial adsorption with increasing ATBS content. The samples showed that the maximum observed apparent in-situ viscosity increased when the bulk viscosity and relaxation time of the solution increased. The information generated in this study can be used to aid in the selection of the most optimal polyacrylamide chemistry, which may not necessarily be the standard 30% AA and 70% AMD copolymer, for sandstone fields operating with moderate/high salinity brines at the upper end of AA-AMD temperature tolerance.
Sancet, G. Fondevila (CAPSA-CAPEX) | Goldman, M.. (CAPSA-CAPEX) | Buciak, J. M. (CAPSA-CAPEX) | Varela, O.. (CIHIDECAR CONICET UBA) | D'Accorso, N.. (CIHIDECAR CONICET UBA) | Fascio, M.. (CIHIDECAR CONICET UBA) | Manzano, V.. (CIHIDECAR CONICET UBA) | Luong, M.. (CIHIDECAR CONICET UBA)
Abstract According to the strategy to search alternative products which can replace (partially) the use of expensive polymers in polymer-flood projects, this work helps to find the optimum combination between polymer and xanthan-gum to develop a mixture that generates viscosity in good economical and rheological conditions. The aim of this work is the characterization of the mixture of a biopolymer (xanthan gum) and a synthetic polyacrylamide in specific proportions and reservoir conditions. Both polymers are suitable for polymer flooding, but they have weaknesses on their own: the polyacrylamide is very susceptible to saline environments and mechanical degradation, while biopolymers as xanthan gum exceed these reservoir conditions but are highly degraded by some bacteria. A polymer blend of mother solutions was prepared by mechanical mixing. It is proved that a blend improves the desirable properties of mobility control if the polymers show miscibility. Several techniques were used to evidence possible interaction between the polymers. A series of tests were performed to provide complementary data regarding molecule structure, miscibility, interaction and stability of the xanthan gum-polyacrylamide mixture at 35/65 proportion in a 16,000 ppm TDS reservoir synthetic brine. The polymer mother solutions and the mixture were lyophilized in order to determine thermal events by Differential Scanning Calorimetry (DSC), Differential Thermal Analysis (DTA) and Thermo Gravimetric Analysis (TGA). Also Fourier Transform Infrared (FTIR) spectroscopic studies and Proton Nuclear Magnetic Resonance (H NMR) were performed to obtain distinctive molecular fingerprint; and Scanning Electron Microscopy (SEM) so as to complete the morphological studies. This work shows detailed techniques of the characterization and the conclusions achieved that confirm the molecular interaction of the blend. DSC analysis at low temperatures evidence similar vitric transitions for xanthan gum and polyacrylamide mother solutions. Vitric transition temperature (Tg) is related to the polymer network packing and hydrodynamic volume, concluding that similar values means that both polymers can travel together through the porous media without being segregated. The single Tg obtained for the mixture could indicate interactions between the polymers. This interaction was also shown in the FTIR analysis: the mixture spectra showed displacement of some signals of the fingerprint zone. On the other hand, the H NMR spectra of the mixture did not show differences with the pure polymers ones. SEM micrographies show no surface separation: xanthan gum deposits over the continued and directional layers of polyacrylamide evidencing phase integration. Blends of bio and synthetic polymers are investigated widely in other industries due to their benefits. Up to date, there are no reports of the use of polymer mixtures in polymer flooding. The results of this work will enable the design of a pilot to be conducted during 2018 on a mature polymer-flooded area with more than 10 years of polymer-flooding (Buciak, 2013).
Liang, Feng (Aramco Services Company: Aramco Research Center–Houston) | Al-Muntasheri, Ghaithan (Saudi Aramco) | Ow, Hooisweng (Aramco Services Company: Aramco Research Center–Boston) | Cox, Jason (Aramco Services Company: Aramco Research Center–Boston)
Summary In the quest to discover more natural-gas resources, considerable attention has been devoted to finding and extracting gas locked within tight formations with permeability in the nano- to microdarcy range. The main challenges associated with working in such formations are the intrinsically high-temperature and high-pressure bottom conditions. For formations with bottomhole temperatures at approximately 350–400°F, traditional hydraulic-fracturing fluids that use crosslinked polysaccharide gels, such as guar and its derivatives, are not suitable because of significant polymer breakdown in this temperature range. Fracturing fluids that can work at these temperatures require thermally stable synthetic polymers such as acrylamide-based polymers. However, such polymers have to be used at very-high concentrations to suspend proppants. The high-polymer concentrations make it very difficult to completely degrade at the end of a fracturing operation. As a consequence, formation damage by polymer residue can reduce formation conductivity to gas flow. This paper addresses the shortcomings of the current state-of-the-art high-temperature fracturing fluids and focuses on developing a less-damaging, high-temperature-stable fluid that can be used at temperatures up to 400°F. A laboratory study was conducted with this novel system, which comprises a synthetic acrylamide-based copolymer gelling agent and is capable of being crosslinked with an amine-containing polymer-coated nanosized particulate crosslinker (nanocrosslinker). The laboratory data have demonstrated that the temperature stability of the crosslinked fluid is much better than that of a similar fluid lacking the nanocrosslinker. The nanocrosslinker allows the novel fluid system to operate at significantly lower polymer concentrations (25–45 lbm/1,000 gal) compared with current commercial fluid systems (50–87 lbm/1,000 gal) designed for temperatures from 350 to 400°F. This paper presents results from rheological studies that demonstrate superior crosslinking performance and thermal stability in this temperature range. This fracturing-fluid system has sufficient proppant-carrying viscosity, and allows for efficient cleanup by use of an oxidizer-type breaker. Low polymer loading and little or no polymer residue are anticipated to facilitate efficient cleanup, reduced formation damage, better fluid conductivity, and enhanced production rates. Laboratory results from proppant-pack regained-conductivity tests are also presented.