Conductivity Maintenance: Long-Term Results from the Use of Conductivity Enhancement Material

SPE Western Regional Meeting

Dusterhoft

et al. 2015

As more wells are drilled and completed in tight, brittle formations, operators rely more on small-sized proppants to help ensure the created complex fractures are propped, and to maintain conductive flow paths for production. Most microfractures generated in the far-field away from the primary fracture branches are believed to return to a closed state soon after the release of hydraulic pressure, unless propping agent has been successfully placed inside such fractures. This paper presents the results of laboratory study, numerical modeling, and field trials, to demonstrate and quantify the effectiveness of a new treatment method for enhancing conductivity of microfractures and primary fractures formed in tight formations, thus helping improve well production.The approach involves using a micro-proppant (MP) and an aqueous-based surface modification agent (ASMA) as part of the pad fluid stage to treat fracture faces of microfractures and leakoff induced fractures before placement of larger-sized proppant into the primary fractures. This coating causes the proppant particulates to adhere to the created fracture faces by forming partial monolayer, thus mitigating settling and enhancing vertical distribution in the fractures. During experimental testing, various shale core samples were split along the core length to create artificial fracture faces. These fracture faces were then exposed to MP or proppant slurry treated with an ASMA, and were then reassembled for core flow testing under closure stress. An effective permeability comparison of the fractured cores, with and without ASMA treated MP or proppant, demonstrated a dramatic effective permeability increase in fractures of the treated cores.Field treatments involved injection of pad fluid containing a low concentration of MP, with and without treating with ASMA in offset wells, to treat the microfractures formed in the far-field regions. Proppant slurry of larger size particulates (100-mesh and larger) then followed to prop the primary fractures and their branches. Production from wells treated with MP have shown to provide significant improvement in terms of liquids production compared to the production of control wells. Reservoir simulation performed in this complex retrograde condensate reservoir supports this result, with sensitivity testing showing that increasing the connected fracture area enables the production of more hydrocarbon liquids at higher sustained production rates.

Section: Discussionmentioning

confidence: 81%

Application of Micro-Proppant to Enhance Well Production in Unconventional Reservoirs: Laboratory and Field Results

Dahl

SPE Western Regional Meeting

Dusterhoft

et al. 2015

“…Instead of allowing formation particulates to migrate through the proppant pack, previous studies have shown that fracture conductivity (and hence, well productivity) can be enhanced and extended by effectively preventing these formation fines from invading the proppant pack (Blauch et al 1999;Lehman et al 2003;Dusterhoft et al 2004). Fines migration should be prevented (or stopped) far away from the wellbore, rather than allowing or waiting for the damage of the formation matrix or proppant pack to occur nearer to the wellbore.…”

Section: Discussionmentioning

confidence: 99%

“…The grain surfaces become tacky, thus having the ability to trap fines and prevent their migration into the pack and through the pack (Nguyen et al 1998 and. In addition to fines control, additional benefits of having proppant with a hydrophobic film coating include reduced fracturing gel damage and reduced proppant pack scale damage resulting in higher sustained fracture productivity (Ali et al 2000;Lehman et al 2003;Weaver et al 2005 andWeaver and Nguyen 2010).…”

Section: Introductionmentioning

confidence: 99%

Maintaining Well Productivity Through Controlling Fines Migration and Scale Formation

Stanciu

et al. 2015

Europec 2015

The intrusion of formation fines and formation sand grains into the proppant pack drastically reduces the conductivity of propped fractures, which can negatively impact well production. This paper describes the development and field treatments using a new form of surface modification agent (SMA) that is a low-tackiness surface modification agent (LTSMA) that can be applied during primary hydraulic fracturing or remedial treatments of propped fractures. Studies were conducted to demonstrate the mechanisms by which this LTSMA controls migration and intrusion of formation sand and fines into the proppant pack, while inhibiting scale formation in the treated pack.Molecular modeling data on the LTSMA suggests that both the polymer backbones and the hydrophobic chains on the polymers are responsible for its reduced tackiness to the treatment equipment and significant scale inhibition ability. Once coated on the proppant as part of hydraulic fracturing treatment, or injected into the proppant pack and formation matrix surrounding the fractures, this LTSMA forms a thin film on the particulates, covering and anchoring the particulates in place. This LTSMA coating also forms a hydrophobic film on the particulate surfaces, inhibiting chemical reactions that lead to scale formation in the pack matrix and subsequent productivity losses.Laboratory experiments using packed beds of proppant, formation sand grains, and various fines were performed to simulate proppant pack conditions and formation fines before and after remedial treatments. Experimental results indicate that treatments with this particular LTSMA effectively control the migration of formation fines into proppant packs and successfully prevent the buildup of scale in various sand packs to maintain the fluid flow paths. No pressure buildup was noticed, opposed to the proppant that was not treated with the LTSMA, for which severe scaling had occurred by 24 hours, leading to an exponential increase in pressure drop across the proppant pack. Examination with scanning electron microscopy analysis clearly demonstrated that no scale was formed in the pore spaces between the treated proppant grains compared to a massive buildup of scale on the proppant particles and in their pore spaces when not coated with the LTSMA.In addition to remedial treatments, LTSMA treatment fluid can be applied while treating formations following an acidizing treatment, during treatment of formations before a high-rate water pack or frac-pack treatment, or as part of a pad fluid to treat the fracture faces before placement of proppant into a fracture and/or a screen annulus.

“…Instead of allowing formation particulates to migrate through the proppant pack, recent studies have shown that fracture conductivity (and hence, well productivity) can be enhanced and prolonged by effectively preventing these formation fines from invading the proppant pack (Blauch et al 1999;Lehman et al 2003;Dusterhoft et al 2004). Fines migration should be prevented far away from the wellbore, rather than allowing or waiting for the damage of the formation matrix or proppant pack to occur.…”

Section: Discussionmentioning

confidence: 99%

Maintain Well Productivity Through Inhibiting Scale Formation and Controlling Fines Migration

SPE Asia Pacific Oil and Gas Conference and Exhibition

Vasquez

Weaver

et al. 2010

Migration of fine particulates and/or scale formation is known to plug up etched channels or pore spaces in proppant packs, causing production decline in wells that have been acidized or completed with high-rate water packs or frac-packs. The removal of such damage caused by plugging is only a temporary solution if the source of the plugging material is not mitigated. This paper presents the results of a series of laboratory tests aimed at demonstrating and quantifying the performance of a treatment fluid for stabilizing formation fines, inhibiting scale formation, and keeping flow channels open through damaged proppant packs after production has been restored.Packed beds of proppant and formation sands were used to simulate frac-pack conditions before and after remedial treatments. The treatment fluid was comprised of a salt-free, aqueous-based solution containing an environmental friendly clay-swelling inhibitor and a water-based agglomerating agent (WBAA). The results show that this WBAA system is applicable to most types of formations, including sandstones, carbonates, and coals. Once injected into the proppant pack and formation matrix, WBAA forms a thin film on the particulates, covering and anchoring them in place, without plugging pore throats. This thin coating does not harden, but remains flexible, allowing the treated formation to withstand high shear stress during high production flow rates. WBAA coating forms hydrophobic film-encapsulating particulate surfaces, inhibiting chemical reactions that lead to scale formation in the pack matrix.The experimental results show that WBAA treatments effectively mitigate the buildup of scale in various sand packs and successfully control the migration of formation fines into proppant packs to maintain well production.