This paper describes the performance evaluation of curable resin coated proppants currently used in Russian Oilfields. The performance of these RCPs is compared based on established API/ISO standards and standard resin coated proppant testing methods currently applied within Schlumberger. These methods investigate further fluid compatibility between fluid systems and resin, proppant pack integrity under a variety and combination of curing conditions and proppant pack integrity under well flowing conditions. In the paper we evaluate the material performance of resin coated proppants used in Russia, showcase new resin coated proppant testing methods and demonstrate the need for firm industry standards devoted to the testing of resin coated proppants. Introduction A common problem after the fracturing stimulation of a well can be the back production of proppant[i],[ii] (proppant flowback). Proppant flowback can occur instantly during well cleanup, over a period of several days to weeks after the fracturing treatment and during the economic life of the well. Proppant flowback often leads to poor fracture conductivity in the near the wellbore region due a reduction in fracture width. This width reduction can act as a choke limiting production from the entire fracture. Proppant that flows back can have a detrimental effect on production equipment, lead to plugging or erosion of surface and downhole completions and lead to loss of revenue during down time when equipment is replaced. In some cases up to 15 % of the proppant placed during a fracture treatment has been known to return during the clean-up period. Root cause analysis of ESP failures attribute up to 30% of the failures to solids/proppant production. The net impact of proppant flowback can result in reduced production, damaged equipment and ultimately loss of revenue. Some method of flowback control is usually implemented to avoid issues with proppant flowback and maximize fracture production. Existing solutions for proppant flowback include curable resin coated proppant (RCP), fibers, deformable beads and resin on-the-fly. The most popular of these solutions remains curable resin coated proppant. Since the late 1970s, curable RCP has been used to control proppant flowback[iii]. The curable resin coatings are designed for a variety of downhole temperatures and can be applied to a variety of sand and ceramic substrates depending on the crush resistance and conductivity required. The effectiveness of using RCP as a proppant flowback control tool has been confirmed by multiple laboratory studies, ?s well as long-term experience of its application. It is widely accepted[iv] that the long-term flowback control, sand control and conductivity resulting from curable RCP is due to the following reasons:chemical consolidation between proppant grains resulting in high compressive strength;higher crush resistance than the substrate due to more effective distribution of stress between particles; andresin coating keeps fines encapsulated after failure of the substrate.
Most of the low-permeability tight gas market that is treated by low-viscosity slickwater fracturing treatments results in ineffective propped fractures due to rapid proppant settling. Currently hybrid fracturing and ultra-lightweight proppants are employed for improving performance of slickwater treatments. The hybrid fracturing methodology uses a combination of linear and crosslinked gels to improve proppant placement. The disadvantages of existing lightweight proppants are their high cost and applicability only to reservoirs characterized by low closure stresses. Novel fiber-laden low-viscosity fluid technology has been developed to improve proppant transport for hydraulic fracturing in low-temperature tight gas formations. Such a system creates a fiber-based network within the fracturing fluid that decouples proppant settling from fluid viscosity. This network entangles proppant, dramatically reduces proppant settling, and provides a mechanical means to transport and place the proppant at greater distances from the wellbore. An additional advantage of the new system lies in fiber degradability, which leads to a nondamaged fracture conductivity with time. Fluid rheology of fiber-laden fluids was measured over a 150-230 °F temperature range under various fiber loadings. Studies showed that under bottomhole temperature and fluid pH fiber decompose and form a water-soluble species. During fiber degradation, the permeability of the fiber-laden system approaches the value of permeability for the baseline system without fiber. Compatibility study of the degradation byproducts with formation water showed no precipitate formation in high salinity environments. The results demonstrate that the new fiber technology ensures uniform proppant placement within a long fracture, provides permeability equal to pure proppant pack values, and offers higher production rates in comparison with conventional fracturing treatments. Introduction Tight-gas formations are characterized by very low permeability values, usually in the range of micro- or nanodarcies. Long effective fracture half-lengths are required to optimize production rates and ultimate recovery in these formations. Good proppant placement throughout the payzone is very important, and minimizing height growth into unproductive adjacent layers significantly improves the economics of the fracturing treatment. Due to the high flow velocities in the propped hydraulic fracture in tight gas formations, there is an additional requirement to minimize non-Darcy flow effects and multiphase flow effects-commonly addressed using round, spherical proppants strong enough to withstand the effective stress in the fracture. All these requirements could be fulfilled by fracturing with low viscosity fluids if it were not for rapid proppant settling. Proppant settling, or even worse proppant settling out of the payzone, severely limits the effective fracture length1. Inability of low viscosity fluid to carry proppant for extended periods at bottomhole temperature leads to a full proppant settling before the fracture closes. Poor carrying properties of such fluids result in poor vertical coverage of the fracture with proppant and therefore non-optimal fracture conductivity. Summarizing the aforementioned, the following general requirements for fracturing tight-gas formations could be defined:Create maximal effective fracture half-lengthContain fracture height within pay zoneMaximize fracture conductivity using correct proppant and clean fluidsEnsure both good vertical coverage and deep placement of the proppant within the fracture. One of the existing ways to minimize particle settling during hydraulic fracturing is to use high concentration polymer crosslinked fluids having excellent proppant transport characteristics. However, being highly viscous, the crosslinked fluids can break out of zone. Furthermore, the high polymer concentration may cause irreparable damage to fracture conductivity. These two factors make this methodology inefficient in formations with extremely low permeability (microdarcies or less).
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractTo achieve maximum production, tight-gas formations require long fractures with contained height growth. This can be achieved by using low viscosity fracturing fluids. Decrease in fluid viscosity typically leads to an increase of proppant settling rate which results in non-uniform proppant placement and reduced effective fracture conductivity. Low-density proppants can offset this effect in low-viscosity fluid, but due to their low strength can be applied only at low closure stresses and relatively low temperatures. A new fluid system was developed especially for fracturing low-permeability formations (less than 0.01 mD). This system allows for high-strength high-density ceramic proppant to be used with reduced polymer loading and significantly decreased proppant settling rates. All these benefits are the result of adding fibers into a fluid system which create a network, helping to suspend proppant during its transport and placement into a fracture.Laboratory studies were performed to determine the fiber's influence on long-term proppant-pack permeabilities. Retained conductivities of ceramic and sand proppant packs over the 175-250 0 F temperature range were measured under various loadings and closure stress ranges. Testing has shown permeability values of the fiber-laden systems are comparable with the values for fiber-free proppant packs. A parallel study was performed on evaluating proppant settling rates in fiberladen fluids in static conditions. Fiber in a fracturing fluid system reduces the rate of proppant settling by greater than three-fold.Special attention is paid to a proper proppant selection for hydraulic fracturing. Improper proppant selection can cause significant damage of proppant pack conductivity and minimize benefits of the fluid system.The results prove that the innovative fiber fluid ensures uniform proppant placement within a long fracture because of fiber presence, provides conductivity comparable to pure proppant pack values, and do not have any limitations at high closure stresses.
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