Compositional Simulation of Condensate Banking Coupled with Reservoir Geomechanics

Deng, Hui; Chen, Z.; Dong, Chao; Nikpoor, M. H.

doi:10.1190/urtec2013-126

Cited by 3 publications

(2 citation statements)

References 8 publications

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“…Gas condensate fluids may form considerable liquid phase amounts at reservoir conditions as the pressure drops during the production phase (Ahmed et al, 1998). As the pressure in the near-wellbore region drops below the dew point, the condensate forms a ring around the wellbore and reduces the gas deliverability (Deng et al, 2013). This phenomenon is called condensate banking, and lean or dry gas reinjection is widely used to mitigate gas productivity drop and to maximize condensate recovery.…”

Section: Theoretical Background Gas Condensate Fieldmentioning

confidence: 99%

An efficient approach for optimizing full field development plan using Monte-Carlo simulation coupled with Genetic Algorithm and new variable setting method for well placement applied to gas condensate field in Vietnam

Jun¹,

Kang

Jeong³

et al. 2016

Energy Exploration & Exploitation

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This paper presents an efficient technique to optimize a gas condensate field development plan under economic uncertainties. Many studies have been conducted to optimize development plan but mostly limited to oil field under fixed economic environments and required huge number of simulation runs. It is proved that black oil model can be a reasonable alternative of compositional model to complete field development optimization within acceptable period when reservoir pressure is higher enough than dew point pressure. This study implements Monte-Carlo simulation to Genetic Algorithm to assess economic uncertainties while optimization procedure is being performed and to avoid duplicating whole optimization procedure by changing economic assumptions. An idea for setting optimization variables for well placement is also introduced to reduce required number of simulation runs. A real field application confirms that the technique can be applied to optimize a gas condensate field with contractual gas sales obligation, and the idea plays a key role to find the optimized solution with limited resources by reducing the number of simulation runs required during the optimization procedure. The proposed technique can be applied to optimize not only full field

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Section: Theoretical Background Gas Condensate Fieldmentioning

confidence: 99%

An efficient approach for optimizing full field development plan using Monte-Carlo simulation coupled with Genetic Algorithm and new variable setting method for well placement applied to gas condensate field in Vietnam

Jun¹,

Kang

Jeong³

et al. 2016

Energy Exploration & Exploitation

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“…This is a critical issue in low-permeability reservoirs because this can impair the productivity of the wells through formation damage by reducing the effective permeability around the wellbore (Orangi and Nagarajan 2015). One of the biggest challenges in dealing with condensate banking in tight reservoirs is that the flow of gas occurs at the fracture, but as the pressure depletes, the condensate bank occurs within the fracture, critically damaging the well (Deng et al 2013). We studied this phenomenon using a numeric simulation model to compare and quantify the damage that condensate banking creates and how best to mitigate the effects of this damage through an optimization of the placement of the horizontal section of the well within the target formation.…”

Section: Introductionmentioning

confidence: 99%

Well Placement Optimization in a Gas Condensate Reservoir to Prevent Condensate Banking

Evans

Ghalambor

Orangi

2016

Day 1 Wed, February 24, 2016

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Horizontal wells with multistage hydraulic fractures have become the most common practice to obtain viable commercial production from shale and tight gas reservoirs. With a marked increase of gas production emerging from these tight reservoirs, it is necessary to further study the effects of formation damage due to condensate dropout and how best to prevent and mitigate this damage. There are two common ways to mitigate and treat condensate banking. The first method is to fracture the existing well. This allows bypassing the condensate and therefore increasing well productivity. The second method is to shut-in the well and allow pressure to build up so that the dropped out liquids are revaporized back into the gas. These options, respectively, involve large capital expenses and temporary decrease of production. Before deploying these solutions, the condensate dropout damage can be strongly reduced at no (field) cost by optimizing the well location.This objective in this study was to determine the optimum well location to mitigate formation damage due to condensate dropout in a tight gas well. Compositional reservoir simulations were conducted with different condensate gas ratios and relative permeability curves to quantify the loss of productivity due to formation damage under different conditions. The target formation was 100 ft thick, and a tartan grid was used to represent the hydraulic fractures within the tight gas well.This study determined that well placement plays a key role in preventing damage due to condensate banking. The optimized placement of the well can drastically enhance the viability of a project by allowing for a larger recovery.

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Understanding Mechanisms for Liquid Dropout from Horizontal Shale Gas Condensate Wells

et al. 2014

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The presence of nanopores in tight, rich-gas-condensate wells (3,000 to ~10,000 scf/STB) may hold long-term gas/oil ratio (GOR) trends constant with time as observed in production data from some North American shales. This finding contrasts with some of the numerical simulation forecasts performed on calibrated pressure/volume/temperature (PVT) models based on bulk laboratory PVT data. Research efforts have pointed to a decrease in the PVT phase envelopes of hydrocarbon fluids confined in nanopores. This would delay the onset of dew point pressure and condensate liquid dropout and could be one of the causes of the observed constant producing GOR in the wells studied. An understanding of fluid properties in nanopores is fundamental to predicting the onset of condensate dropout in shale reservoirs. One approach may be molecular dynamics simulations that can shed the light on the difference in behavior of larger-chain hydrocarbon molecules at kerogen surfaces and bulk pore space. Additionally, shale gas condensate production management may be more fully optimized by understanding both the effects of hydraulic fracture degradation with drawdown and liquid dropout in the production string. An integrated approach of this kind can help optimize liquid-rich shale reservoir production management.

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Compositional Simulation of Condensate Banking Coupled with Reservoir Geomechanics

Cited by 3 publications

References 8 publications

An efficient approach for optimizing full field development plan using Monte-Carlo simulation coupled with Genetic Algorithm and new variable setting method for well placement applied to gas condensate field in Vietnam

An efficient approach for optimizing full field development plan using Monte-Carlo simulation coupled with Genetic Algorithm and new variable setting method for well placement applied to gas condensate field in Vietnam

Well Placement Optimization in a Gas Condensate Reservoir to Prevent Condensate Banking

Understanding Mechanisms for Liquid Dropout from Horizontal Shale Gas Condensate Wells

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