Summary Conditions leading to the plugging of perforations in wells and pore throats in porous formations are investigated experimentally. Accurate correlations are developed for the effect of pore throat to particle size ratio on flowing fluid conditions and plugging time leading to particle bridging. It is demonstrated that the critical pore throat to particle size ratio vs. particle-volume fraction Reynold's number can be correlated satisfactorily using an exponential function, and the dimensionless plugging time vs. reciprocal particle-volume fraction yields an exponential-type correlation. Such empirical correlations can be used to determine and alleviate the conditions that induce perforation and pore plugging by migrating particles in petroleum reservoirs. These correlations reveal that the critical pore-to-particle diameter ratio below which plugging occurs may be greater than the unit physical limit. Introduction Plugging of perforations in wells and pores of porous formations occur frequently during various operations of oil and gas industry, including water flooding, drilling, perforation, and workover. Particles migrating at sufficiently high concentrations with a particle to hole size ratio may form bridges across and narrow down the perforations and pore throats, reducing the flow rate through reservoirs. This may cause severe damage to the productivity of the oil and gas wells. Hence, the operational conditions need to be adjusted to avoid the plugging of pores and perforations by suspended particles. The mechanism of pore-throat plugging in porous formations is of interest in geotechnical engineering and the petroleum industry. Pore-throat plugging can occur by size exclusion or by the jamming of fine particles during fluid flow. Migration and entrapment of fine particles during flow in petroleum reservoirs can lead to clogging and decreased oil productivity. The pore throats control the rate of flow through the interconnected pore space inducing a gate or valve effect (Chang and Civan 1991).

This study experimentally and numerically investigates formation damage induced by suspended particles in the drilling fluid and its effect on limiting their near-wellbore invasion. The study applies the NMR and X-Ray digital radiography tprovide valuable insights into damage mechanisms along the formation and depth of invasion. Formation damage caused by drilling fluids is one of the key factors for economic success in oil and gas field developments. The measured permeability reduction obtained from laboratory test by injecting particulate drilling fluid in a representative core sample is used to determine empirical parameters used to model the particle migration and deposition in porous media by means of a robust simulation of the relevant processes. The study provides a concept to develop the ability to evaluate drilling fluids in term of their formation damage potential.

Conditions leading to plugging of perforations in wells and pore-throats in porous formations are investigated experimentally.Accurate correlations are developed for the effect of pore-throat-to-particle-size ratio on flowing fluid conditions and plugging time leading to particle bridging. It is demonstrated that the critical pore-throat-to-particle-size ratio vs. particlevolume-fraction Reynolds number can be correlated satisfactorily using an exponential function and the dimensionless plugging time vs. reciprocal-particle-volume-fraction yields an exponential-type correlation. Such empirical correlations can be used to determine and alleviate the conditions which induce perforation and pore plugging by migrating particles in petroleum reservoirs. These correlations reveal that the critical pore-to-particle diameter ratio below which plugging occurs may be greater than the unit physical limit.

The approach focuses on the use of analytical and 3D dynamic compositional numerical models to physically describe the condensate banking phenomenon and to better understand the real deliverability in terms of gas and condensate production. The model is also built to compare the benefits of hydraulic fracturing over the horizontal well in Bien Dong POC development campaign. In this study, an analysis of pressure transient test data is conducted to investigate the condensate bank radius. Construction of a radial model is used as a benchmark model to compare it to an equivalent Cartesian grid model in term of productivity. The paper is focused on the development of a workflow for the analysis and selection of grid size and methods used in the 3D compositional model. Then the model is used for horizontal and hydraulic fracturing designs. When the flowing bottomhole pressure falls below dew point, the condensate dropouts in the near wellbore reduce permeability to gas through relative permeability effects; hence the well productivity is reduced significantly. The prediction of gas condensate well production will strongly depend on condensate banking evaluation and modeling. It is important that a model is built to describe the condensate banking phenomenon accurately to avoid over-estimating well performance. It is shown that an integrated model which incorporates Generalized Pseudo Pressure (GPP) and Local Grid Refinement (LGRs) can reproduce almost exactly with the benchmark model. The presented procedure and analysis can serve as a guideline for full field gas condensate reservoir modeling. The study also suggests that un-fractured horizontal well is not attractive compared to hydraulic fractured vertical well. Fractured half-length optimization design should be based on economic criterion. The study addresses the complexity of gas condensate behavior around the near wellbore region. The workflow of building an accurate 3D compositional model allows Bien Dong POC to have a reliable resource in reservoir development and management plans. The applicability of this work is confirmed by actual field case study in offshore Vietnam. It contributes to the knowledge of performance of gas condensate reservoirs and supports representative modeling of detailed model and recovery processes.

This case study investigated the effects of formation reservoir properties, aquifer influx, and production scheme on ultimate recovery and production behaviors of a gas-condensate sandstone reservoir Sand20 offshore Vietnam. Optimum production strategy was then formulated to maximize the hydrocarbon recovery while reducing the water treatment cost. The approach focused on the construction of benchmarked radial numerical models to describe the water coning and breakthrough phenomenon and to better understand the impacts of aquifer on deliverability and ultimate recovery of a gas-condensate reservoir. In this study, all factors that have potential impacts on gas and oil ultimate recoveries such as gas production rate, completion length, aquifer size, reservoir horizontal permeability, and permeability anisotropy were investigated. The numerical results showed that for permeability greater than 100 mD, withdrawal rates do not have significant impacts on reservoir gas recovery, while the oil recovery decreases with increasing withdrawal rates. To maximize the ultimate oil recovery, minimize total water production, delay water breakthrough time, and prolong field production life, the wells are recommended to produce at a reasonable low gas flow rate. On the other hand, a minimum gas production rate is required to recover all the reserves to meet the field's production strategy. Aquifer size was found to have no impact on water breakthrough time for this gascondensate reservoir, but it can have big impact on the recovery factor and the total water production. This study also suggested that perforation interval should be sufficiently long to maximize recovery. Finally, it was found that water-gas ratio does not increase rapidly until approximately 90% of perforation interval is flooded with water.