Gas hydrate interparticle cohesive forces are important to determine the hydrate crystal particle agglomeration behavior and subsequent hydrate slurry transport that is critical to preventing potentially catastrophic consequences of subsea oil/gas pipeline blockages. A unique high-pressure micromechanical force apparatus has been employed to investigate the effect of the molecular structure of industrially relevant hydrate antiagglomerant (AA) inhibitors on gas hydrate crystal interparticle interactions. Four AA molecules with known detailed structures [quaternary ammonium salts with two long tails (R1) and one short tail (R2)] in which the R1 has 12 carbon (C12) and 8 carbon (C8) and saturated (C–C) versus unsaturated (CC) bonding are used in this work to investigate their interfacial activity to suppress hydrate crystal interparticle interactions in the presence of two liquid hydrocarbons (n-dodecane and n-heptane). All AAs were able to reduce the interparticle cohesive force from the baseline (23.5 ± 2.5 mN m–1), but AA-C12 shows superior performance in both liquid hydrocarbons compared to the other AAs. The interfacial measurements indicate that the AA with an R1 longer alkyl chain length can provide a denser barrier, and the AA molecules may have higher packing density when the AA R1 alkyl tail length is comparable to that of the liquid hydrocarbon chain on the gas hydrate crystal surface. Increasing the salinity can promote the effectiveness of an AA molecule and can also eliminate the effect of longer particle contact times, which typically increases the interparticle cohesive force. This work reports the first experimental investigation of high-performance known molecular structure AAs under industrially relevant conditions, showing that these molecules can reduce the interfacial tension and increase the gas hydrate–water contact angle, thereby minimizing the gas hydrate interparticle interactions. The structure–performance relation reported in this work can be used to help in the design of improved AA inhibitor molecules that will be critical to industrial hydrate crystal slurry transport.

Surfactants are often used to stabilize aqueous dispersions. For example, surfactants can be used to prevent hydrate particles from forming large plugs that can clog, and sometimes rupture pipelines. Changes in oil composition, however dramatically affect the performance of said surfactants. In this work we demonstrate that aromatic compounds, dissolved in the hydrocarbon phase, can have both synergistic and antagonistic effects, depending on their molecular structure, with respect to surfactants developed to prevent hydrate agglomerations. While monocyclic aromatics such as benzene were found to disrupt the structure of surfactant films at low surfactant density, they are expelled from the interfacial film at high surfactant density. On the other hand, polycyclic aromatics, in particular pyrene, are found to induce order and stabilize the surfactant films both at low and high surfactant density. Based on our simulation results, polycyclic aromatics could behave as natural anti-agglomerants and enhance the performance of the specific surfactants considered here, while monocyclic aromatics could, in some cases, negatively affect performance. Although limited to the conditions chosen for the present simulations, the results, explained in terms of molecular features, could be valuable for better understanding synergistic and antagonistic effects relevant for stabilizing aqueous dispersions used in diverse applications, ranging from foodstuff to processing of nanomaterials and advanced manufacturing. Dispersions are found in a variety of applications, from foodstuff to minerals processing, from biotechnology to nanotechnology, from 3D printing to advanced manufacturing. One relevant application in the energy sector concerns flow assurance. In oil and gas pipelines, the simultaneous presence of natural gas and water can lead to the formation of hydrate plugs, which could clog, and sometimes rupture the pipeline. In addition, gas hydrates can form in many offshore energy processes 1. The unintended formation of hydrate plugs can cause disruptions in oil and gas production, as well as large negative environmental consequences 1-3. Among other approaches to manage gas hydrates is the stabilization of hydrate particles in hydrocarbon dispersions. Specifically designed surfactants, known as anti-agglomerants (AAs), are optimized to prevent hydrate plug formation in flow assurance 4,5. AAs are believed to adsorb on hydrate particles by their hydrophilic head groups, while the AAs tail groups are soluble in the hydrocarbon phase. The hydrate particles, as well as water droplets, are expected to be covered by a film of AAs and oil, making them repel each other and disperse 5-9. This rich system offers an ideal platform to test our fundamental understanding regarding the stabilization of dispersions using surfactants. In fact, laboratory and field observations alike show that many phenomena determine the AAs' performance. Small changes in the molecular structure of the surfactants, changes in salt content, and in gas/oil and i...

The development of a high-temperature seawater-based fracturing fluid has received much attention because it offers a solution to fresh water shortages; however, the rheological properties suffer significantly as a result of interactions between dissolved ions with fluid components. Various strategies have been investigated to address this challenge, including seawater treatments that ultimately remove the highly soluble and insoluble ionic moieties to yield a fracturing fluid with reliable rheological characteristics. Most polymer-based fracturing fluids have limited salt tolerance. Interactions between the polymer and divalent cations in seawater inhibit proper polymer hydration, thus preventing generation of an elastic polymer network and potentially affecting the crosslinking mechanism. In this study, concentrations of critical ions in seawater were reduced using a reliable seawater treatment. This treatment allowed a reliable fluid at higher temperatures and also considerably reduced the scaling tendency of the fluid. The fluid presented herein, designed in the treated seawater, yields a stable elastic polymer network when used in conjunction with stabilizing additives and is capable of effectively delivering proppant down hole. This newly developed formulation uses a combination of instant and delayed crosslinkers and additional stabilizing additives required at optimum concentrations to yield a stable fluid system in the treated seawater. At high temperatures, the addition of typical ion sequestration agents failed to eliminate the negative interaction between dissolved ions and fluid stability, thus requiring water pre-treatment. The fluid system exhibits reliable rheological properties and yields a clean broken fluid for excellent proppant pack cleanup in high total dissolved solids (TDS) waters up to 350°F. Typical guar-based fracturing fluids require a high pH (greater than 10) to maintain rheological stability at high temperatures. The fracturing fluid presented herein was developed at pH 9 in treated seawater and maintained its elasticity and viscosity over a long period of time at temperatures up to 350°F. An added benefit of controlling the pH and not surpassing pH 9.5 was also revealed—scale control. This study discusses the development of a new seawater-based fracturing fluid for use in high-temperature wells. This can result in a paradigm shift in source water use for hydraulic fracturing.

To control proppant flowback during well production, proppant is often coated with a curable resin to obtain bonding between grains. However, current curable resin systems often have short cure times, allowing the resin coating on proppant to cure prematurely before complete placement into the target fractures, or creating operational issues if removal of the proppant from the wellbore is required. As another option, proppant can be coated with a tackifier polymer to maintain propped fracture conductivity by mitigating migration and intrusion of formation particulates into the proppant pack. The use of only a tackifier polymer does not offer sufficient cohesion to lock the proppant in place under high production flow rates. This paper presents the results of a laboratory study to demonstrate and quantify the performance of a new resin system that provides both tackiness and the option of delayed consolidation to effectively overcome these shortcomings. To achieve both delayed consolidation and agglomeration properties, a study involved coating proppants with a resin mixture comprised of a curable resin, a tackifier polymer, and a catalyst (when needed) before blending the coated proppant grains into a fracturing fluid. After the coated proppant was packed in place, consolidation levels were observed to increase as a function of time and temperature. Mixing ratios between resin and tackifier components of this new resin system are adjustable to achieve the designed coating performance (e.g., high consolidation strength with low tackiness, or vice versa). Catalyst addition controls cure kinetics to obtain consolidation for the proppant pack, when necessary. Combining the delayed consolidation and agglomeration properties into a single proppant coating provides the ability to immobilize the proppant and also mitigate formation sand and fines migration to greatly enhance and sustain proppant pack conductivity. Potential applications for field treatments using this resin system are discussed. In multistage fracturing treatments, the delayed curing resin allows a more flexible schedule so that drilling/milling techniques are not required to retrieve the consolidated proppant left inside the wellbore between fracturing stages. With respect to frac-pack type treatments, delayed consolidation also allows effective removal of excess coated proppant by reversing out after its placement into the fractures and screen-casing annulus packing is complete.

As more wells are drilled and completed in deeper reservoirs, various methods are being applied to overcome choking effects in propped fractures and enhance well productivity. Choking effects can result from permeability damage caused by fracturing gel residues, low proppant concentrations, proppant crushing from high closure stresses, or embedment/intrusion of formation materials into the proppant pack. This paper describes the laboratory testing of a new well stimulation method that can use low-quality sand for generating stable, highly conductive channels within a propped fracture to help maximize and maintain production of hydrocarbon from the formation reservoir to the wellbore.Mini-pillars of various particulate materials were formed by coating them with a tackifying agent or a curable resin and placing them in molds to be cured before testing. These mini-pillars were installed in conductivity cells using various layout configurations to determine the effect of closure stresses on pillar height, diameter expansion, conductivity measurements, and choice of particulate materials. Laboratory experiments were performed to evaluate the formation and stability of mini-pillars and proppant-free channels surrounding the pillars.The obtained results in this study indicate that flow capacity of conductive channels prepared from proppant pillars with low-quality sands was comparable to those prepared using high-quality sand or high-strength manufactured proppant. Proppant crushing was not observed to be a concern when applying fine particulates during this fracturing process because flow capacity of proppant-free channels between aggregate masses dominates flow through the propped fracture, making the formation of proppant pillars with high-quality sand or high-strength proppant unnecessary. As long as proppant pillars are held in place without being previously dispersed or broken up to ensure the integrity of proppant-free channels, low-quality sand or particulates can be a practical and economical source of solids material for preparing these proppant aggregates.