Post stimulation proppant flow back has long been an issue of the hydraulic fracturing process. The most common means of remedying proppant flowback has been to treat proppants with a resin coating. However, the most daunting factor in using resin-coated proppants is the resulting high price, which can be in excess of four times the price of untreated proppants. Additionally, resin coated proppants often need to be activated with exposure to temperature and pressure. In the case of low temperature/low closure stress reservoirs, additional chemical activators are required which further increases the cost. A proppant flowback control measure which is cost-effective and can perform over a wide variety of reservoir conditions would be advantageous to the hydraulic fracturing process. A new technology has been developed to control proppant flowback that is a non-toxic, cost effective, and operationally easy. After being coated with a proppant consolidation aid (PCA), the proppant depends on a physical mechanism rather than chemical bonding to increase proppant pack resistance to flowback. There is no minimum closure stress, temperature, or shut-in time requirements associated with the use of this technology, and the coating can be applied to all or just selectively some of the proppant stages, which allows more flexibility available to the operators in flowback design and production strategy. Laboratory testing will illustrate the efficacy of sand consolidation using the PCA coating. Simple lab bottle consolidation testing will demonstrate a comparison between untreated and treated proppants. Large scale tubing flow tests will also demonstrate the ability of the coated proppant to resist movement during fluid flow relative to untreated sand, and will also show the cleanup ability of the sand at higher flow rates in the event of a sand-off where proppant remains undesirably in the wellbore. Other testing will reveal additional benefits to the sand treatment such as improved sand pack conductivity and increased compressive strength. Computed Tomography (CT) analysis will be used to explain one of the mechanisms that results in increased proppant pack conductivity. Temperature stability testing will be included to show the wide potential application window of the PCA chemistry.

Non-hydrolyzed polyacrylamide (PAM) and partially hydrolyzed polyacrylamide (HPAM) are commonly used polymers in various industrial applications, including in oil and gas production operations. Understanding the microbial utilization of such polymers can contribute to improved recovery processes and help to develop technologies for polymer remediation. Microbial communities enriched from oilfield produced water (PW) and activated sludge from Alberta, Canada were assessed for their ability to utilize PAM and HPAM as nitrogen and carbon sources at 50 °C. Microbial growth was determined by measuring CO 2 production, and viscosity changes and amide concentrations were used to determine microbial utilization of the polymers. The highest CO 2 production was observed in incubations wherein HPAM was added as a nitrogen source for sludge-derived enrichments. Our results showed that partial deamination of PAM and HPAM occurred in both PW and sludge microbial cultures after 34 days of incubation. Whereas viscosity changes were not observed in cultures when HPAM or PAM was provided as the only carbon source, sludge enrichment cultures amended with HPAM and glucose showed significant decreases in viscosity. 16S rRNA gene sequencing analysis indicated that microbial members from the family Xanthomonadaceae were enriched in both PW and sludge cultures amended with HPAM or PAM as a nitrogen source, suggesting the importance of this microbial taxon in the bio-utilization of these polymers. Overall, our results demonstrate that PAM and HPAM can serve as nitrogen sources for microbial communities under the thermophilic conditions commonly found in environments such as oil and gas reservoirs. Electronic supplementary material The online version of this article (10.1186/s13568-019-0766-9) contains supplementary material, which is available to authorized users.

The first fracture treatment using crosslinked guar was performed in 1969. Since then guar and its derivative polymers have dominated hydraulic fracturing. But because of volatility and supply issues with guar gum that have surfaced during peak activity years, industry has turned to alternatives. One of those is Carboxymethylcellulose (CMC) that just like guar comes from food industry. CMC is also used in pharmaceuticals as a thickening agent, and in the oil and gas industry as an ingredient in drilling mud. Use in hydraulic fracturing is surprisingly limited. The objective of this paper is to demonstrate successful cases of CMC based treatments over traditional guar and surfactant based treatments used in linear and foamed applications. This paper presents several cases from treatments performed on formations such as Cardium, Montney, Belly River, and Dunvegan. Presented production comparison will demonstrate that wells treated with CMC based hydraulic fracturing fluid system yield similar performance when compared to wells treated with guar, its derivatives, and surfactant based fluid systems. Cost savings realized when switching to CMC based fluid systems are also discussed in the paper. Laboratory tests described, performed, and results shared to demonstrate the performance of CMC compared to guar, Carboxymethylhydroxypropyl guar (CMHPG), and surfactant systems. The paper attempts to provide degree of confidence to the operators looking for cleaner alternatives to industry established fluid systems and shows that these can be successfully implemented without additional risk or cost.

Due to the mixed-wettability phenomenon found in Montney rock fabric, choosing the ideal flowback enhancer/surfactant to Enhance Post Frac Oil Recovery (EPFOR), has not been a straightforward task. Along with the wettability ambiguity, Montney exhibits nano-Darcy permeability making laboratory testing challenging. Conventionally at the flowback stage, injected treatment water is recovered as soon as possible with the intent to reduce the water saturation in the invasion zone and newly created complex network of fractures. On the contrary, the soakback/slowback concept has been recently adapted as a new practice for flowback management. The well is left shut in for an extended period to promote counter-current imbibition phenomena, where the residual hydraulic fracturing fluid can imbibe deeper in the formation matrix driven by osmotic and capillary forces. The imbibition mechanism into the matrix and dissipation of water saturations beyond the invasion zone help clean up water in the propped fractures and can help to ramp up peak hydrocarbon rates. Common surfactant chemistry applied in hydraulic fracturing on Montney can be rendered inefficient due to the fast-adsorbing effect in the near-wellbore (hydraulic fracture face) area. Instead, an innovative nano-particle surfactant (NPS) has been developed, that can penetrate through formation rock and oil layers more efficiently, carrying low salinity hydraulic fracturing fluids deeper in the rock matrix, by reducing the in-situ interfacial tension between crude oil and the stimulation fluids and altering the mixed wettability of the formation rock to a more water-wet state. Additionally, the fabric of the Montney formation contains clays, which displays osmotic membrane characteristics in the presence of high salinity gradients (stimulation fluid and connate water). Once stimulation fluid invades the pore space through clay platelets, pore pressure increases and an expulsion of hydrocarbon from pore space is followed. In this paper, we examine properties of NPS through a rigorous laboratory testing protocol with Montney core and liquid hydrocarbon specimens. Interfacial tension testing shows that when NPS is added at a minimum loading of 0.1 L/m3 in the stimulation fluid, a further interfacial tension reduction of approximately ~41.3% is reached in comparison to other commercially available petroleum surfactants at the same loading. Long-term Amott cell testing performed with Montney core samples in the presences of NPS displays a substantial increase in oil recovery when compared to the blank. This paper attempts to detail the development of the NPS through laboratory and field testing which includes the characteristics of hydraulic fracturing fluids, produced hydrocarbons, and formation rock interactions.

Calcium sulfate in the form of gypsum (CaSO4.2H2O) and anhydrite (CaSO4) is one of the most prevalent evaporite minerals typically found in the prolific middle Devonian carbonate rocks of the Western Canadian Sedimentary Basin (WCSB). Strong mineral acids, in particular hydrochloric acid (HCl), are employed to enhance permeability in the near wellbore area of the oil wells in these carbonate-bearing formations during matrix stimulation and hydraulic fracturing treatments. When calcium sulfate (CaSO4) comes in contact with the live acid, partial dissolution can occur. As the acid solution is progressively spent inside the carbonate rock, the concentration of unassociated calcium ions will increase. These ions will become readily available to react with the sulfate ions in the neutralized solution and cause, the unavoidable re-precipitation of CaSO4 crystals in the pore throat, therefore severely plugging the newly created flow channels. Based on Le Chatelier's principle and the common ion effect, the addition of a soluble calcium salt to the treating acid package has been an economical oil field practice established to suppress the initial dissolution of CaSO4. However, a secondary protection mechanism is still required because sulfate-rich connate water could commingle with the spent acid solution during swabbing and/or flowback operations, reaching the ideal conditions for CaSO4 precipitation. To date, most of the CaSO4 scale inhibitors that have been applied for acid treatments relied on either the retardation of CaSO4 crystal growth, or the creation of soluble complex salts with the calcium ions. This paper intends to detail the development and laboratory testing of a broad spectrum scale inhibitor specially formulated for high salinity and acid solutions that not only prevents the precipitation of CaSO4, but also helps to inhibit the initial dissolution of CaSO4. Introduction Covering a vast extension of 1.4 million square kilometers (Bowers 1997), The WCSB defines its coordinates between the southwestern border of the Canadian shield in Manitoba and the eastern flank of the Canadian Rocky Mountain system in British Columbia. Within the WCSB, approximately half is composed of carbonate reservoirs of the Devonian age. These Carbonate formations combine for a project reserve of 15 billion barrels of oil and 35 trillion cubic feet of natural gas (Li 2002). These important reserves of hydrocarbons have been successfully exploited since the late 1940's (Milligan 1998).