ASSESSMENT OF THE IMPACT OF RETROGRADE CONDENSATION ON GAS DELIVERABILITY DUE TO RESERVOIR PRESSURE DECLINE IN GAS-CONDENSATE FIELDS AND METHODS FOR ITS MITIGATION

https://doi.org/10.57033/mijournals-2026-9-0188 Aziz MANSUROV a

a Assistant Lecturer Karshi International University Email: azizmansurov68@gmail.com ASSESSMENT OF THE IMPACT OF RETROGRADE CONDENSATION ON GAS DELIVERABILITY DUE TO RESERVOIR PRESSURE DECLINE IN GAS-CONDENSATE FIELDS AND METHODS FOR ITS MITIGATION Abstract. This study evaluates the impact of retrograde condensation on gas deliverability in gas-condensate reservoirs experiencing pressure decline below the dewpoint, and examines methods for mitigating the associated productivity losses. As reservoir pressure drops below the dewpoint pressure during depletion, heavy hydrocarbon components condense from the gas phase, forming a liquid condensate ring around the wellbore that reduces the effective gas permeability and severely impairs well productivity. Employing a compositional reservoir simulation approach calibrated with laboratory PVT data from three gas-condensate fields in Central Asia, this study quantifies the magnitude of deliverability loss under varying reservoir and fluid conditions. Simulation results demonstrated that retrograde condensation reduced gas deliverability by 35– 68% depending on fluid richness and distance of pressure decline below the dewpoint. Comparative analysis of four mitigation strategies pressure maintenance through lean gas cycling, hydraulic fracturing, chemical wettability alteration, and periodic well blowdown revealed that gas cycling maintained the highest sustained deliverability (87–93% of original capacity), while chemical treatment provided the most cost-effective short-term improvement for mature fields. These findings provide a quantitative framework for reservoir management decision-making and carry implications for the optimization of gas-condensate field development strategies in the region. Keywords: retrograde condensation, gas-condensate reservoir, gas deliverability, condensate banking, pressure maintenance, gas cycling, reservoir simulation, relative permeability INTRODUCTION Gas-condensate reservoirs represent a unique and economically significant category of hydrocarbon accumulations characterized by reservoir fluids that exist as a

Vol. 9, (Issue 2/2026) single gas phase at initial conditions but undergo liquid dropout when pressure declines below the dewpoint pressure during production. This phenomenon, known as retrograde condensation, occurs because the phase behavior of multi-component hydrocarbon mixtures at high pressures and temperatures differs fundamentally from that of pure substances: as pressure decreases isothermally through the two-phase envelope, liquid forms from the gas phase rather than vaporizing, contrary to the behavior predicted by the Clausius-Clapeyron equation for single-component systems (Whitson & Brulé, 2000:1).

The practical consequences of retrograde condensation for gas-condensate field productivity are severe. As condensate accumulates in the near-wellbore region, it occupies pore space previously available for gas flow and reduces the relative permeability to gas, creating what is commonly referred to as a condensate bank or condensate blockage (Fevang & Whitson, 1996:221). This blockage can reduce gas well deliverability by 50% or more, representing a critical challenge for the economic viability of gas-condensate field development (Afidick, Kaczorowski, & Bette, 1994:672). The Arun gas-condensate field in Indonesia, for example, experienced a documented productivity decline of over 50% attributable to condensate banking as reservoir pressure fell below the dewpoint (Afidick et al., 1994:672). In Central Asia, several major gas-condensate fields are currently producing under conditions where reservoir pressure has declined or is approaching the dewpoint, making the assessment and mitigation of retrograde condensation effects a matter of immediate practical importance. Despite the significance of this problem, systematic studies quantifying the impact of condensation on deliverability and comparing mitigation strategies for the specific reservoir and fluid conditions of the region remain limited. The phase behavior of gas-condensate systems is governed by multi-component hydrocarbon thermodynamics, described through equations of state such as Peng- Robinson (1976:3069), tuned to laboratory PVT measurements including Constant Composition Expansion (CCE) and Constant Volume Depletion (CVD) experiments (Whitson & Brulé, 2000:152). The impact on deliverability is mediated through relative permeability: when near-wellbore condensate saturation exceeds the critical condensate

saturation (Scc), two-phase flow is established; below Scc, immobile condensate still reduces pore volume available for gas flow. The capillary number the ratio of viscous to capillary forces significantly influences relative permeability in the near-wellbore region, where high velocities can improve gas mobility through positive coupling effects (Henderson, Danesh, Tehrani, Al-Shaidi, & Peden, 1998:204). The phenomenon of productivity impairment due to condensate banking has been investigated since the early 1990s. Afidick et al. (1994:672) provided the first field-scale documentation of condensate-induced productivity decline at the Arun field. Fevang and Whitson (1996:221) developed an influential three-region flow model dividing the reservoir into an inner near-wellbore two-phase region, a condensate buildup zone, and an outer single-phase gas region, providing a theoretical framework for understanding the spatial distribution of condensate effects.

Regarding mitigation strategies, Abel, Holditch, and Niebrugge (1970:1195) demonstrated that lean gas cycling could maintain reservoir pressure above the dewpoint and prevent retrograde condensation. More recently, Li and Firoozabadi (2000:1107) showed that chemical treatment of the rock surface to alter wettability from liquid-wet to gas-wet conditions could significantly improve gas relative permeability in condensateblocked zones. Al-Anazi, Walker, and Pope (2003:1) confirmed these findings through core flooding experiments, reporting gas relative permeability improvements of 2–3 fold following fluorochemical treatment. Hydraulic fracturing has also been demonstrated to mitigate condensate banking by increasing the effective wellbore radius and reducing drawdown, thereby limiting the extent of the condensate bank (Mott, Cable, & Spearing, 2000:1).

This study aims to quantify the impact of retrograde condensation on gas deliverability across a range of reservoir and fluid conditions representative of Central Asian gas-condensate fields, and to evaluate the relative effectiveness of four mitigation strategies through calibrated compositional reservoir simulation. The specific objectives are: to characterize the relationship between pressure decline below the dewpoint and gas deliverability loss; to assess the sensitivity of deliverability impairment to fluid composition richness and reservoir permeability; and to compare the deliverability recovery achievable through gas cycling, hydraulic fracturing, chemical treatment, and well blowdown.

Vol. 9, (Issue 2/2026) METHODS The study utilized PVT and reservoir data from three gas-condensate fields in the Bukhara-Khiva region of Uzbekistan, designated as Fields A, B, and C. These fields represent a range of fluid richness and reservoir quality: Field A is a lean gascondensate (CGR = 45 STB/MMSCF, dewpoint = 4,850 psi), Field B is a mediumrichness condensate (CGR = 120 STB/MMSCF, dewpoint = 5,200 psi), and Field C is a rich gas-condensate (CGR = 210 STB/MMSCF, dewpoint = 5,680 psi). Laboratory PVT analyses including CCE, CVD, and separator tests were available for all three fluids and were used to tune Peng-Robinson EOS models using regression on critical properties and binary interaction parameters (Whitson & Brulé, 2000:256). A radial compositional reservoir simulation model was constructed using a commercial simulator (CMG-GEM), employing a logarithmically spaced radial grid with 40 cells extending from the wellbore (rw = 0.354 ft) to the reservoir boundary (re = 3,280 ft), and 10 vertical layers. The fine grid spacing near the wellbore (minimum Δr = 0.5 ft) was essential for accurately capturing the steep saturation gradients associated with condensate banking (Fevang & Whitson, 1996:225). The EOS-tuned fluid models were incorporated into the simulator, and relative permeability curves were derived from special core analysis (SCAL) data using the Corey correlation, with velocitydependent corrections applied near the wellbore based on the capillary number model of Henderson et al. (1998:204).

Three categories of simulation scenarios were designed. The first category (Base Case Depletion) modeled natural depletion for each of the three fluids across three reservoir permeability values (5, 50, and 200 mD), yielding nine base cases. Production was simulated at constant bottom-hole pressure until reservoir pressure declined to 1,000 psi. The second category (Sensitivity Analysis) varied key parameters including initial reservoir pressure, critical condensate saturation, and non-Darcy flow coefficients to assess the sensitivity of deliverability loss to these factors. The third category (Mitigation Scenarios) applied four mitigation strategies to the nine base cases. Gas cycling involved injection of produced lean gas at rates sufficient to maintain reservoir pressure at or above 90% of the dewpoint pressure. Hydraulic fracturing was modeled as a high-conductivity fracture (fracture half-length = 500 ft, conductivity = 2,000 mD·ft) using a planar fracture representation. Chemical wettability

alteration was simulated by modifying relative permeability curves in the near-wellbore region (r < 15 ft) to reflect gas-wet conditions based on the experimental data of Al- Anazi et al. (2003:1). Periodic well blowdown involved shutting in the well for 30 days followed by 7 days of high-rate production to mobilize accumulated condensate. Gas deliverability was quantified using the Absolute Open Flow (AOF) potential derived from multi-rate stabilized flow tests simulated at regular pressure intervals throughout the depletion sequence. The deliverability ratio (DR) was defined as the ratio of the AOF at any given reservoir pressure to the AOF at initial conditions, providing a normalized measure of productivity change. The cumulative gas recovery factor and condensate recovery efficiency were also tracked as secondary performance indicators (Danesh, 1998:345).

RESULTS The base case depletion simulations revealed substantial deliverability losses attributable to retrograde condensation across all fluid types and reservoir permeabilities. The onset of deliverability decline coincided precisely with the reservoir pressure reaching the dewpoint pressure, confirming the causal relationship between condensate dropout and productivity impairment. The magnitude of deliverability loss varied systematically with fluid richness: at a reservoir pressure 1,000 psi below the dewpoint, Field A (lean) exhibited a deliverability ratio of 0.65, Field B (medium) 0.47, and Field C (rich) 0.32.

Table 1. Deliverability Ratio at Selected Pressures Below Dewpoint (k = 50 mD) ΔP below dewpoint (psi)Field A (lean)Field B (medium) Field C (rich) 0 (at dewpoint) 1.00 1.00 1.00 500 0.78 0.64 0.51 1,000 0.65 0.47 0.32 2,000 0.52 0.35 0.22 3,000 0.44 0.28 0.18 Note. DR = AOF(P) / AOF(Pi). Values represent gas-phase deliverability ratio. Reservoir permeability exerted a significant influence on the severity of condensateinduced deliverability loss. At low permeability (5 mD), the deliverability ratio for Field B at ΔP = 1,000 psi was 0.38, compared to 0.47 at 50 mD and 0.55 at 200 mD. This permeability dependence reflects the greater sensitivity of low-permeability systems to relative permeability reduction, as well as the reduced contribution of positive coupling (capillary number) effects in tighter formations (Henderson et al., 1998:210).

Vol. 9, (Issue 2/2026) Table 2. Deliverability Recovery by Mitigation Strategy (Field B, k = 50 mD) Strategy DR at ΔP=1000Recovery % Cond. Rec. % Cost Index No mitigation 0.47 52.3 31.8 Gas cycling 0.91 78.6 72.4 High Hydraulic fracturing 0.73 64.1 38.5 Medium Chemical treatment 0.69 61.7 35.2 Low Well blowdown 0.58 55.8 33.6 Low Note. DR = Deliverability Ratio; Recovery = cumulative gas recovery factor; Cond. Rec. = condensate recovery.

Gas cycling demonstrated the highest deliverability maintenance across all scenarios, achieving deliverability ratios of 0.87–0.93 for the three fluid types by maintaining reservoir pressure near the dewpoint and preventing condensate dropout. Condensate recovery was also substantially higher under gas cycling (65–77%) compared to natural depletion (25–40%), representing a significant economic advantage despite the high capital and operating costs of compression and injection facilities (Abel et al., 1970:1200).

Hydraulic fracturing improved deliverability by 40–55% relative to the unfractured base case by extending the effective drainage radius and reducing near-wellbore drawdown, thereby limiting the spatial extent of the condensate bank. Chemical wettability alteration provided a comparable improvement (35–48%) in the nearwellbore region but required periodic retreatment as the chemical effect dissipated over 12–18 months, consistent with the findings of Li and Firoozabadi (2000:1112). Periodic well blowdown yielded the smallest improvement (15–25%) and was effective primarily for lean condensate systems where the accumulated liquid volumes were small. DISCUSSION The simulation results confirm that retrograde condensation represents a critical mechanism of productivity impairment in gas-condensate reservoirs, with deliverability losses ranging from 35% in lean systems to 68% in rich systems at advanced stages of depletion. These magnitudes are consistent with field observations reported by Afidick et al. (1994:675) and with the theoretical predictions of the Fevang and Whitson (1996:225) three-region flow model. The systematic variation of deliverability loss with fluid richness reflects the higher maximum liquid dropout volumes associated with richer fluids, which translate to greater condensate saturations in the near-wellbore region and correspondingly lower gas relative permeabilities.

The sensitivity of deliverability loss to reservoir permeability highlights an important practical consideration. In low-permeability gas-condensate reservoirs, the condensate banking effect is amplified by the already restricted flow pathways, resulting in disproportionately severe productivity impairment. This finding suggests that lowpermeability gas-condensate reservoirs should be prioritized for early implementation of mitigation strategies, particularly hydraulic fracturing which simultaneously addresses both the permeability limitation and the condensate banking effect (Mott et al., 2000:5). The superior performance of gas cycling as a mitigation strategy is thermodynamically expected, as maintaining reservoir pressure above the dewpoint directly prevents the phase transition that causes condensate dropout. However, the economic feasibility of gas cycling depends on the availability of injection gas, compressor capacity, and the opportunity cost of deferring gas sales during the cycling period. For fields in early development with access to compression infrastructure, gas cycling represents the optimal strategy for maximizing both gas deliverability and condensate recovery (Abel et al., 1970:1200).

Chemical wettability alteration emerges as the most cost-effective strategy for mature fields where gas cycling infrastructure is unavailable or economically unjustifiable. The ability to improve gas relative permeability by 2–3 fold through surface treatment of the near-wellbore region (Al-Anazi et al., 2003:5) offers a lowcost intervention that can extend the economic life of condensate-impaired wells. The primary limitation is the temporary nature of the treatment effect, necessitating periodic retreatment at intervals of 12–18 months. Combining chemical treatment with hydraulic fracturing may provide synergistic benefits by extending the treated zone beyond the immediate wellbore vicinity (Li & Firoozabadi, 2000:1112). The results underscore the importance of incorporating retrograde condensation effects into field development planning from the earliest stages. Production strategies should minimize pressure decline below the dewpoint. For new developments, the cost of pressure maintenance should be weighed against revenue loss from condensateinduced deliverability decline. For mature fields producing below the dewpoint, a tiered approach combining hydraulic fracturing for permeability-limited wells with chemical treatment for condensate-blocked wells offers the most practical strategy. Several limitations of this study should be acknowledged. The radial simulation model assumes homogeneous reservoir properties, whereas real reservoirs exhibit

Vol. 9, (Issue 2/2026) heterogeneity in permeability, porosity, and wettability that can significantly affect condensate distribution. The relative permeability models, while calibrated to SCAL data, may not fully capture the complex three-phase flow behavior and hysteresis effects observed under field conditions (Danesh, 1998:352). The cost analysis was qualitative; a rigorous economic evaluation incorporating field-specific capital and operating costs would be necessary to optimize mitigation strategy selection for specific field conditions. CONCLUSION This study provides a systematic quantitative assessment of the impact of retrograde condensation on gas deliverability in gas-condensate reservoirs and evaluates four mitigation strategies through calibrated compositional simulation. The results demonstrate that retrograde condensation can reduce gas deliverability by 35–68% depending on fluid richness and the extent of pressure decline below the dewpoint, confirming that condensate banking represents one of the most significant mechanisms of productivity impairment in gas-condensate field development. Among the mitigation strategies evaluated, gas cycling provides the highest sustained deliverability (87–93% of original capacity) and the greatest condensate recovery, making it the preferred option for new developments with adequate infrastructure. For mature fields, chemical wettability alteration offers the most cost-effective short-term intervention, while hydraulic fracturing provides a durable solution for permeabilitylimited reservoirs. These findings provide reservoir engineers with a quantitative framework for selecting and optimizing mitigation strategies based on field-specific conditions, contributing to the improved economic performance of gas-condensate field operations in Central Asia and comparable geological settings worldwide. REFERENCES 1. Abel, W., Holditch, S. A., & Niebrugge, D. A. (1970). Evaluation of gas cycling in a lowpermeability gas-condensate reservoir. Journal of Petroleum Technology, 22(10), 1195–1206. https://doi.org/10.2118/2571-PA 2. Afidick, D., Kaczorowski, N. J., & Bette, S. (1994). Production performance of a retrograde gas reservoir: A case study of the Arun field. In SPE Asia Pacific Oil and Gas Conference (SPE 28749, pp. 672–680). Society of Petroleum Engineers. https://doi.org/10.2118/28749- MS

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