The phenomenon of fines migrating through porous and permeable paths is well-known, as are the issues related to fines migration. During the life of a producing well, fines can migrate and reduce formation permeability by clogging pore throats of the mineral grains and reduce conductivity of proppant packs placed by hydraulic fracturing treatments, Frac Packs, or by gravel pack operations. Such fines migration can eventually lead to reductions in well production. The primary contributing factors that release fines are high fluid velocity, changes in salinity, wettability, pH, and rock failure. Use of a surface modifying agent (SMA), which can immobilize fines in place, helps minimize or mitigate fines migration. However, solvent-based SMAs are difficult to apply as a remedial treatment, and this limits their applicability. This paper discusses the use of an aqueous-based surface modifying agent (ASMA) that can be used to help mitigate fines migration. The ASMA is a conductivity enhancer that immobilizes fines by locking them in place as a result of its tacky surface. Because it is hydrophobic in nature, it resists water flow without hampering hydrocarbon flow.The ASMA can be pumped into formations having permeabilities greater than 100 md as a remedial treatment. It also can be coated onto proppants immediately before pumping them downhole.To demonstrate the efficiency of the ASMA, a number of laboratory experiments were conducted on sand packs consisting of a sand-fines mixture and proppant, which closely simulated actual downhole conditions. Control tests (without the ASMA treatment), pre-coating of proppant pack tests, and remedial treatment tests were performed at different flow rates to study the effect of fines migration along with the efficiency of the ASMA as a technique to mitigate the issue.

For a successful hydraulic fracturing operation, two of the most important properties required from fracturing fluids are transport proppant into the fractured zone and minimum damage to formation and proppant pack conductivity. As the fluid is pumped downhole, it experiences thermal and shear thinning. Shear recovery and thermal stability are critical in terms of successful fracture creation and proppant placement. These fluid properties can be controlled by proper selection of crosslinker and linkable groups. Thermal stability of fluid at high temperatures can be increased by proper selection of gel stabilizers and it also reduces the amount of gelling agent to be used. Conventional gel stabilizer contains sulfur which could contribute to H 2 S gas when consumed by sulfate reducing bacteria. H 2 S gas is not only corrosive in nature but also harmful to health and thus, although it performs well, several operators seek sulfur-free stabilizers that can perform equivalent to sulfur-based compounds.This paper describes a sulfur-free gel stabilizer developed for enhancing the stability of fracturing fluid, allowing a lower concentration of gelling agent. This gel stabilizer is sulfur-free, nonhazardous, and biodegradable. It also provides better stability for fluids compared to conventional sulfur containing gel stabilizers.Further showcased is the improvement in stability of crosslinked fracturing fluid using the sulfur-free stabilizer under high temperature (HT) conditions of 280 to 320°F. Rheological tests performed using a Chandler high-pressure/high-temperature (HP/HT) viscometer with and without stabilizer are discussed. Results shows a significant change in terms of fluid stability in the presence of this new stabilizer as it provides better stability compared to conventional sulfur containing stabilizer. Also, shear sensitivity tests performed under multiple high shear rate cycles between 100-935-1700 s -1 showed excellent shear recovery after every high shear cycle by completely rehealing in less than 30 seconds.

Sand production can be challenging for many operators in unconsolidated formations. The production of formation sand and fines can cause erosion damage to both surface and downhole equipment, resulting in major well intervention and sand disposal costs. Conventional resin consolidation systems have been successfully used to prevent solids production in short, homogenous intervals. However, resin consolidation attempts in longer intervals have resulted in erratic success rates, which could be attributed to a lack of complete and uniform treatment of the entire interval length. A recently developed aqueous-based resin (ABR) system has helped provide effective and efficient treatment of significantly longer intervals, has improved health, safety, security, environmental (HSSE) compatibility, and can help improve various operational considerations. This paper discusses results of laboratory testing and the subsequent successful treatment using the ABR system within a well located in Nile Delta, which was the first attempt of its kind in Egypt. Sieve analysis revealed unsorted formation sand, which usually requires a gravel pack completion, rather than a standalone screen; however, because of limitations with respect to wellbore diameter (5 in.), it was difficult to complete the well using conventional gravel pack completion methods. Additionally, the well had a history of unsuccessful treatment using a non-resin product, which modifies the surface potential charges of the sand grains and reduces the repelling forces between them. The well was still producing sand after that treatment; thus, the decision was made to treat the interval using the ABR system. Thereafter, hydrocarbon production, at a rate of 5.5 MMscf/D, was monitored and sand production from the well decreased by more than 95%, with no impairment to hydrocarbon production.

Hydraulic fracturing is often performed using resin-coated proppants to minimize proppant flowback during hydrocarbon production, whether the resin is precoated or coated on-the-fly as the treatment is pumped. Resin-fracturing fluid interaction can have a negative effect on fluid stability or resin consolidation, or both. This paper examines the effects of resin-fluid interactions on fluid stability, proppant consolidation strength, and strategies to mitigate the effects. Components of resins can change the fracturing fluid stability by interacting with crosslinker or breaker, or by changing the fluid pH. To offset the effect of a resin, the breaker/crosslinker/buffer concentration should be tuned while pumping resin-coated proppant. Similarly, resin-fluid interaction can decrease consolidation strength by disturbing resin-curing kinetics or reducing grain-to-grain contact, which can increase the possibility of proppant flowback during production. The influence of resins on fracturing fluid stability was evaluated by conducting rheology testing. The effect of fracturing fluids on the consolidation strength of resin was evaluated by comparing unconfined compressive strength (UCS) of proppant packs. The stability of zirconate and borate crosslinked guar fluids, when treated with coated on the fly liquid resin-coated proppant (LRCP), was lower than non-treated fluids at 260°F as a result of breaker activation by the resin components. The desired fluid stability was attained by lowering breaker concentration in liquid resin-treated fluid. During another round of testing, a second type of LRCP, based on different chemical functionality, increased the stability of synthetic polymer fluid at 400°F. Likewise, a rise in fluid stability was observed when guar fluid was treated with resin pre-coated proppant (RCP) at 200 and 250°F. The improved fluid stability is associated with reduction in active breaker concentration in the presence of furan resin and RCP. The UCS value of the proppant pack prepared from fracturing fluid-treated RCP was ~16 to 45% lower than the proppant pack without this fluid treatment. Additionally, the UCS value of proppant pack prepared using fracturing fluid-treated LRCP decreased by ~30%. However, the measured UCS value of LRCP pack with fracturing fluid exposure was higher than the RCP pack measured value even without exposure to this fluid. Incorporating LRCP instead of using RCP during fracturing operations could address the proppant flowback issue and possibly result in higher conductivity of propped fractures. It could help ensure economic production rates and prevent costs associated wellbore cleanup, downhole tool damage, erosion and damage to the tubular, chokes, valves and separators, and refracturing of the well. Ultimately, it could help maintain a lower cost per barrel of oil equivalent (BOE).

Southeast offshore India reservoirs have high-temperature deep water wells with significantly high pressures and unconsolidated sandstone formations. Controlling sand production is a major issue from inception to well completion and throughout the life of the well. A high density brine is required due to the high bottom hole pressures, thus executing sand control operations using such a high density brine as the base fluid for the gravel pack carrier fluid combined with the elevated temperatures is a significant challenge. A case is presented where a high-density temperature-resistant gravel packing fluid was optimized for a BHT of 320°F using a high-density brine. Additionally, the pH of the fluid was crucial considering the significant presence of CO2 in the formation, which was anticipated to affect asset integrity due to corrosion at low pH. A biopolymer-based fluid with oxidizing breaker was required in 14.2 ppg potassium-cesium formate brine and 12.5 ppg potassium formate brine. The fluid required evaluation for rheology and stability at 320°F, and at a shear rate of 170 s-1 with two conditions of viscosity to be sustained in the range of 75- 150 cP and 150-250 cP for the initial four-hour duration. The same fluid, after four hours, was also required to be broken within fourteen days. The fluid with the optimized formulation in regard with stability and rheology was further required to pass an acceptable sand suspension of ≤ 5% settling. Finally, the optimized fluid was required to show negligible corrosion effects on the downhole metallurgies. The stability and rheology were studied using a HPHT concentric cylinder viscometer. The sand suspension and corrosion characteristics were studied using an HPHT autoclave. The same fluid was studied with an acid breaker as a contingency for wells without CO2-related issues. After an extensive study, 12.72 gal/Mgal liquid gel concentrate of biopolymer when hydrated in 14.2 ppg and 15.45 gal/Mgal liquid gel concentrate of biopolymer, when hydrated in 12.5 ppg, providing viscosity in the range of 150-250 cP with 3 gal/Mgal and 5 gal/Mgal oxidizing breaker were selected, respectively. The optimized formulations passed sand suspension and had a pH in the range of 8-10, which imparted negligible corrosion loss to chrome- and nickel-based metallurgies. At the same conditions, the fluid showed acceptable results with 20 gal/Mgal organic acid breaker where the pH was ≤ 7. The combination of a commonly used biopolymer and a mixed formate brine produced a thermally stable fluid with unconventional chemistry, applicable for high-temperature, high-density conditions. With further study, it is expected that the temperature limit of this fluid can be extended beyond 320°F. The formulation for potassium formate brine was also tested at using field scale equipment to check for ease of mixing, reproducibility of results and for determining friction values when pumped at a certain rate via shunts. The fluid was mixed with relative ease using standard batch mixers and replicated the properties that were determined on a lab scale. The fluid also depicted superior proppant carrying capacities and lower friction numbers than expected which would enable lowering of overall surface pressures and surface pumping requirements.