A new laboratory work procedure has been developed to evaluate and test the performance and effectiveness of chemical-sealant-based loss circulation materials (CS-LCMs), which are often used in cases of severe-to-total losses. These unconventional testing methods should be useful tools to evaluate the integrity of loss circulation material (LCM) products under downhole conditions in terms of differential pressure buildup and how quickly such LCMs can arrest lost circulation. Evaluation and testing of LCMs in the laboratory before field application are crucial. Conventionally, the plugging capacity of particulate LCMs is tested against various-sized slotted discs using a permeability plugging apparatus (PPA), and integrity is tested in terms of sealing capacity and fluid loss value. Testing the performance of CS-LCMs required another means that included plugging extra-large vugs and building a significant differential pressure that could sustain the drilling fluid column. Pumpability of CS-LCMs and mechanical strength performance over time were evaluated using a high-pressure/high-temperature (HP/HT) consistometer, ultrasonic cement analyzer (UCA), and modified PPA following this fit-for-purpose procedure. Extensive laboratory testing revealed that the new testing method was highly compatible with almost all types of chemical-based LCMs, including resin, gunk squeeze, and thixotropic slurries. The effectiveness and performance of several commercially available CS-LCMs were measured using different vug sizes (i.e., up to tens of millimeters). Thickening time of LCMs were observed pumpable [i.e., <70 Bearden units of consistency (Bc)], even after hours of conditioning at bottomhole circulating temperatures (BHCTs). As per API routine practice, tested slurry is deemed unpumpable if Bc exceeds 70. However, the thickening time of gunk squeeze LCMs were observed to be significantly high in a short interval of time once aqueous and nonaqueous streams mixed together. Gunk-based LCMs build high differential pressures and compressive strength over the same periods of curing time at bottomhole static temperature (BHST) and pressure compared to thixotropic-based LCMs. Appropriate laboratory testing and evaluation of chemical-based LCMs under downhole conditions are highly recommended before field trail/application. This new testing/evaluation method should help minimize operational risk and nonproductive time (NPT) at the rig site.

Numerous lost circulation materials (LCMs) are sold in the global market to cure losses in highly fractured formations, but the success rate remains minimal. Lost circulation (LC) is a common challenge of global operators and service companies during either drilling or the oilwell construction phase of development and exploration. A new chemical-sealant-based LCM (CS-LCM) was developed to cure severe-to-total losses in highly fractured formations. The new CS-LCM is dispersed in a nonaqueous carrier fluid (NAF) and quickly forms a highly malleable viscous mass upon exposure to an aqueous reactant fluid and then sets harder under a wide range of temperatures. Comprehensive and systematic tests were conducted on the new CS-LCM to determine the speed of the reaction at an optimized interval of time upon interaction with the reactant. Testing performed on the new CS-LCM included evaluating its flowability before and after the reaction and estimating the compressive strength. Additionally, the developed strength robustness of the CS-LCM was evaluated by its ability to withstand large differential pressures across extra-large holes (31 mm) in test media (simulating vugs in a formation). The reaction rate of the CS-LCM showed measurable right-angle viscosity (RAV) development once the CS-LCM was preconditioned at a bottomhole circulation temperature (BHCT) and allowed to mix with preconditioned (at BHCT) reactant. A significant amount of compressive strength (>500 psi) buildup was observed in less than 1 hour of reaction time, which sustained more than 1,000 psi differential pressure on large vugs. The fast increase in viscosity (i.e., RAV) and quick strength development are the result of fast-reacting chemical additives present in the mixture. Additionally, the resultant set CS-LCM was determined to be soluble in 15% hydrochloric (HCl) acid at ambient temperature; hence, it is a viable solution for a reservoir section. The new CS-LCM was developed to mitigate severe-to-total losses in highly fractured formations by means of RAV development followed by rapid strength buildup in a short interval of time, thus helping prevent overdisplacement away from the wellbore, hence minimizing nonproductive time (NPT) and drilling mud losses.

The application of liquid resin in hydraulic fracturing helps to increase hydrocarbon production by improving conductivity, controlling proppant flowback, inhibiting fines migration, and reducing sand production. This study compares natural sand and proppant in terms of the grain-to-grain relationship (texture) of coated and uncoated samples and describes how microfractures, micropores, and grains are filled and encapsulated by liquid resin. During proppant placement, the concentration of the resin can delay the curing time, which induces consolidation of the proppant pack in the fractures. By extending the curing period, there is more time for the proppant to develop grain-to-grain contact in the fracture as well as for capillary action to pull the liquid-resin coating to the contact points of the proppant grains, thereby providing a highly cohesive consolidated proppant pack. The resin concentration used falls within the oilfield industry’s applicable practices. Several evaluation techniques were used to understand the crystallinity and morphology of coated and uncoated sand/proppant. These techniques included thin section petrography, scanning electron microscopy (SEM), and geomechanical tests. Photomicrographs analysis and SEM images have shown the presence of a very large amount of monocrystalline quartz in the uncoated sand samples, which also displayed reduced mechanical strength as a result of microimperfections in the uncoated sand. A comparative study showed that after resin coating the angular and microfractured sand, mechanical properties of the angular and microfractured sand improve as a result of enhanced interlocking effects of this type of sand. This paper provides a qualitative description of the variation in coated and non-coated sand/proppant in terms of grain-to-grain contact. Moreover, the study also hypothesizes how resin-coated sand can help to fill in micropores and microfractures.

In the recent era of increasing oil and gas production, hydraulic fracturing is a proven economical technique to extract trapped hydrocarbons from tight reservoirs. A major factor associated with hydraulic fracturing is the significant quantity of proppant necessary and the high total contributing cost per well. For deep reservoirs, such as in the Middle East (ME), expensive, synthetic high-strength proppant (HSP) is necessary to withstand high closure stresses exceeding 15,000 psi. A new type of propping agent, a composite structure comprising low-performance sand from local sources in the ME, now exists that is capable of operating under these high closure stresses. Transforming low-performance sand into stable sand-based composite aggregates is a significant development, providing an abundant supply of low-cost propping agent that can enhance and sustain well productivity. This paper demonstrates the sustainable performance of novel thin sheets of the sand-based composite aggregates under application conditions. Analyses of the performance measurements illustrate the unique and necessary properties these aggregates should exhibit to be successful in hydraulic fracturing. Development of a new type of propping agent requires new techniques to measure performance. Most of these techniques apply common geophysical, chemical, and mechanical methods, while other techniques require considerable adaptation of traditional API testing methods. Performance of sand-based composite aggregates and synthetic HSP using these methods highlights the crucial and necessary aggregate properties. Laboratory simulation of a post-fracturing scenario showed that low-performance sand, after conversion into sand-based composite aggregates, can withstand high closure stresses up to 10,000 psi. The measured conductivity of the channels is significantly higher than traditional synthetic proppant packs, and the aggregates are sufficiently strong to avoid fines generation. These observations indicate that sand can provide an effective alternative to HSP, which allows successful hydraulic fracturing in regions where synthetic proppants are cost prohibitive. Finding an alternative to costly synthetic proppant has become more important in recent years. While the natural sand in the ME region is compositionally different and mechanically weaker than synthetic proppants and high-quality sands available in the USA, transforming the sand into composite structures provides unique performance properties. Because the sand is commercially abundant, this novel solution is a viable option.

A detailed study comparing various properties and attributes of local Saudi Arabian sand (processed and unprocessed) and high-strength proppant (HSP) for hydraulic fracturing applications is discussed. Further, quartz grain crystallinity, texture, quality, and mechanical durability (strength) are described and an insight into the prospects of sand application viability during hydraulic fracturing is provided. An in-depth comparison of processed sand, unprocessed sand, and readily available HSP widely used in the industry was performed. It is well known that the Middle East region, particularly Saudi Arabia, has an abundance of sandstone formations ranging from the Cambrian to Quaternary age; outcrops of these formations extend from northern to southern parts of Saudi. These formations have varying grain sizes and other physical attributes that must be studied to grade their possible performance as hydraulic fracturing proppants. Unprocessed sand samples were collected from various central and southern Saudi sandstone formations. Petrographic analysis, including thin section and scanning electronic microscopy (SEM), was conducted on sand samples to quantify the percentage of polycrystalline quartz grains and define their surface features. Crush-resistance testing was performed on the samples to compare the mechanical durability of the sands and HSP. The results of this study confirmed that polycrystalline quartz grains are more abundant in coarse-grained sandstones than those fine-grained. Mechanical durability decreased with an increased percentage of polycrystalline quartz grains, strained grains (with undulose extinction), and surface features. The metamorphic nature of the quartz grain source rock and intense chemical weathering along the quartz grain surface reduce its strength. HSP demonstrates greater mechanical durability compared to processed and unprocessed sand, keeping in mind, the processed sand was from a specific sandstone formation. The suitability of Saudi sandstones for the petroleum industry's use is dependent on the mechanical durability of quartz grains, which, in turn, depends on the source and chemical weathering of those grains. Comparatively, HSP is more durable and mechanically strong; however, processed sand has an edge over unprocessed sand.