Richard D. Rickman

A Study of Proppant-Formation Reactions

Based on long-term API conductivity data, proppants are generally chosen to optimize fracturing cost versus fracture conductivity. This long-term data is acquired by measuring conductivity for two days at simulated conditions of closure stress and reservoir temperature. It is recognized that the majority of the conductivity damage to a proppant pack occurs rapidly during the first day at simulated conditions. It is clear on examination of raw data that conductivity has not reached equilibrium after two days of flow, but rather it is still declining. Investigators who have studied the effect of longer flowtime on fracture conductivity of proppants have all concluded that the decline in conductivity continues for a much longer time. Much attention has been given to the mechanical properties of proppants to aid in the selection of the best material for a particular fracture treatment. These properties include: size, proppant-size distribution, sphericity, hardness, crush resistance, and acid solubility. Other than acid solubility, little information about the chemical reactivity of the proppants has been noted. Recent work has demonstrated that, at some reservoir conditions, certain proppants become significantly chemically reactive. This paper presents the proppant as starting material for geochemical reactions with various aqueous fluids saturated in typical formation minerals. Methods have been developed for rapid testing of these interactions, and test results clearly demonstrate how important proppant chemical reactivity is as losses in proppant-pack permeability of 50–90% were obtained, owing to the genesis of cementatious and porosity-filling minerals. In addition, some proppant chemistries were found to be much more susceptible to these types of reactions, losing much of their mechanical strength in a surprisingly short period of time. Results from this study indicate that operators who rely solely on API test methods in evaluating the suitability of proppants for particular downhole conditions might miss significant damage potential from geochemical reactions occurring between the proppant and formation fluids.

Foaming Aqueous-Based Curable Treatment Fluids Enhances Placement and Consolidation Performance

Conventional solvent-based resins (SBRs) have often been used to resolve solids-production problems in producing wells by coating the particulates, such as formation sand, fines, and proppant, with a curable resin to hold the grains together without reducing the treated pack’s permeability. However, the SBRs have low flashpoints that can present safety issues during storage, handling, and well-completion operations. These resin systems have been typically applied in short intervals of less than 30 ft and have had limited success in longer intervals. With the recent development and applications of aqueous-based resins (ABRs), these drawbacks have been overcome. Because solvent-based chemicals are replaced with aqueous brines as carriers in treatment fluids, ABRs have high flashpoints, similar to those of water. Additionally, because ABRs are aqueousbased fluids, they can be foamed so that the operator may simply bullhead the fluid directly into the wellbore to treat long intervals without requiring a rig or zone isolation packers. This paper presents the results of laboratory experiments aimed at understanding and quantifying the performance of ABR treatment fluids in consolidating weakly or unconsolidated formation sands or loose proppant packs. Consolidation strengths and scanning electron micrographs of the treated formation sand or proppant packs were analyzed to identify the mechanisms behind the treatment fluids in providing cohesion between particulates and how the pore channels within a pack matrix remain open, minimizing permeability loss. Both foamed and nonfoamed ABRs were determined to provide effective consolidation levels to the treated formation sandpacks, regardless of whether foamed or not, aqueous post-flush fluid was applied. However, only foamed ABRs allowed resin to remain on the proppant after the treated pack was overdisplaced with nitrogen gas or a nonaqueous fluid, resulting in high consolidation strength and retained permeability. Foaming ABRs enhances the effectiveness of their placement into formation intervals by providing an effective means for diversion and better coverage, and extending treatment-fluid volume. When applied using bullheading or coiled tubing, potential applications of ABR systems include primary or remedial treatments of weakly or unconsolidated formations for sand control or fines stabilization and remedial treatments of propped fractures for proppant-flowback control.

Remediation of Proppant Flowback-Laboratory and Field Studies

This paper presents the results of laboratory studies and field case histories of a remedial treatment technique using a lowviscosity consolidation fluid system that is placed into the propped fractures by coiled tubing (CT) or jointed pipe coupled with a pressure pulsing tool. The treatment fluids are designed to provide consolidation (for previously placed proppant) near the wellbore to glue the proppant grains in place without damaging the permeability of the proppant pack. Laboratory flow testing indicates that the proppant pack in a fracture model under closure stress only requires lowstrength bonds between proppant grains to withstand high production flow rates. The consolidation treatment transforms the loosely packed proppant in the fractures and the formation sand close to the wellbore into a cohesive, consolidated, yet highly permeable pack. Field case histories are presented and the treatment procedures, precautions, and recommendations for implementing the treatment process are discussed. One major advantage of this remedial treatment method is the ability to place the treatment fluid into the propped fractures, regardless of the number of perforation intervals and the length of the perforated intervals without mechanical isolation between the intervals. The fluid placement efficiency of this process makes remediation economically feasible, especially in wells with marginal reserves.