## 2 Well Integrity Considerations in High-Temperature and  
Harsh Environments  
Well integrity is influenced by both wellbore and reservoir conditions, including formation fluids, pressure, and temperature variations [19; 20]. When the injection fluid is cooler than the formation temperature, or in geothermal wells with significant thermal gradients, casing expansion and contraction occur longitudinally. The casing expansion and shrinkage are prevented and constrained by the cement, creating either compressive or tensile stress in the casing and, consequently, plastic deformation in the cement. These deformations can induce microfractures at the cement-formation and cement-casing interfaces, compromising zonal isolation [21]. Additionally, casing joint decoupling may arise due to extreme drilling conditions, further endangering well integrity.  
Figure 1: Mechanical properties of various self-healing cement materials, including compressive strength (**top**), Young’s modulus (**middle**), and Poisson’s ratio (**bottom**). Each bar represents a different cement recipe, color-coded based on the corresponding author [10; 14; 15; 16; 17; 18].  
Corrosion is another critical factor, as it degrades casing strength, leading to failures that threaten long-term well stability. Elevated temperatures exacerbate these issues by reducing the mechanical strength of casing materials, thereby lowering their capacity to withstand burst and collapse pressures. As a result, thermal effects can significantly impair well integrity and, in extreme cases, lead to well failure. Many of these issues originate from cement degradation due to mechanical, thermal, or chemical stresses [22]. At high temperatures, the cement experiences thermal fluctuation in geothermal wells, leading to the development of micro-annuli and micro-cracks due to thermal stresses. Also, cement strength deteriorates either during placement or post-hardening, with the situation worsening in the presence of CO2 or H2S, which chemically interact with the cement and accelerate its degradation.  
Previous studies have shown that above the critical temperature range of 104-160 \({}^{\circ}\)C, cement strength declines as temperature and aging increase [18]. Ref. [23] analyzed casing failure modes, focusing on trapped fluid expansion in the casing-to-casing annulus, suggesting that while tie-back liners could mitigate this issue, they introduce other operational challenges. Proper construction and completion techniques were identified as crucial in minimizing such risks.  
Downhole corrosion rates are typically more severe than those in near-surface well sections [24]. Geothermal wells face corrosion issues similar to those encountered in sour oil and gas environments, including pitting, wear, corrosion fatigue, and erosion [25]. To address these concerns, ref. [26] developed Thermal Shock Resistant Cement (TSRC) composites with self-healing properties, which demonstrated an 86% recovery in compressive strength (CS) after a five-day healing period, compared to only 36% recovery in Portland cement under similar conditions.  
Recent advancements in self-repairing polymer-cement formulations have been explored, including Calcium Aluminate Phosphate (CaP) cement and Sodium Silicate-Activated Slag (SSAS) cement [27]. These materials offer cost-effective solutions, as they incorporate industrial by-products from coal combustion and steel manufacturing. To enhance cement resistance in acidic environments, ref. [28] recommended incorporating 5% BWOC olivine microparticles, which act as sacrificial materials available for carbonation.