Recovery Optimization in a Multi-Reservoir Offshore Gas Field With Water Influx

Hower, T.L.; Lewis, D.R.; Owens, R.W.

doi:10.2118/24865-ms

Cited by 10 publications

(3 citation statements)

References 4 publications

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“…However, a reservoir simulation study by Hower et al (1992) showed that increasing production rate could cause water coning in key production wells. In fact, the simulation model predicted that to increase recovery, the production rate should be lowered rather than accelerated.…”

Section: Author(s) Agree That This Article Remain Permanently Open Acmentioning

confidence: 99%

Optimization of Gas Recovery using Co-production technique in Water Drive Reservoir

Maselugbo¹,

Onolemhemhen²,

Denloye³

et al. 2017

J. Petroleum Gas Eng.

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Recovery factor for gas reservoirs are highly dependent on factors such as initial reservoir pressure, abandonment pressure and the type of reservoir drive mechanism. Producing gas reservoirs with active water drive mechanism possess a lot of challenge to the field operator since optimum production of gas is dependent on reduced pressure. Material balance model was used to derive basic reservoir and production parameters thereafter Excel was used to simulate the parameters for both conventional and co-production scenarios using a field data from the Niger Delta Basin. The reservoir contains three producing wells with conventional technique, while co-production has three wells, producing gas from the up-dip and one well producing water from the down-dip. The simulated results show that gas production rate from the three wells changed with respect to the production strategies. Under conventional, gas production rate from the three wells was at a constant rate of 19MMSCF/D for a long period of time. However, under co-production technique, gas production rate was at a constant rate of 38MMSCF/D for a short period of time. Under conventional method, 231.85BCF of gas was recovered from 356.713BCF of gas initially-in-place with recovery factor of 65% until water cut set-in at an abandonment pressure of 2000 psia. However, under co-production technique, the simulated result shows that there was an optimum recovery of gas of up to 92% recovery which is 27% above the conventional technique and the reservoir pressure was depleted to 1000 psia before water cut set-in.

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Section: Author(s) Agree That This Article Remain Permanently Open Acmentioning

confidence: 99%

Optimization of Gas Recovery using Co-production technique in Water Drive Reservoir

Maselugbo¹,

Onolemhemhen²,

Denloye³

et al. 2017

J. Petroleum Gas Eng.

View full text Add to dashboard Cite

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“…One of these methods is the production of residual trapped gas by continuing the water-cut wells operation with the next extraction of gas from the gas-liquid mixture [5]- [8]. This method has significant disadvantages.…”

Section: Introductionmentioning

confidence: 99%

Studying the influence of the carbon dioxide injection period duration on the gas recovery factor during the gas condensate fields development under water drive

Matkivskyi¹,

Kondrat²

2021

Min. miner. depos.

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Purpose. Studying the process of carbon dioxide injection at the boundary of the initial gas-water contact in order to slow down the formation water inflow into producing reservoirs and increase the final hydrocarbon recovery factors. Methods. To assess the influence on gas recovery factor of the duration of carbon dioxide injection period at the initial gas-water contact, a reservoir development is studied using the main Eclipse and Petrel hydrodynamic modeling tools of the Schlumberger company on the example of a hypothetical three-dimensional model of a gas-condensate reservoir. Findings. The dependence of the main technological indicators of reservoir development on the duration of the carbon dioxide injection period at the initial gas-water contact has been determined. It has been revealed that an increase in the duration of the non-hydrocarbon gas injection period leads to a decrease in the formation water cumulative production. It has been found that when injecting carbon dioxide, an artificial barrier is created due to which the formation water inflow into the gas-saturated intervals of the productive horizon is partially blocked. The final gas recovery factor when injecting carbon dioxide is 61.98%, and when developing the reservoir for depletion – 48.04%. The results of the research performed indicate the technological efficiency of carbon dioxide injection at the boundary of the initial gas-water contact in order to slow down the formation water inflow into producing reservoirs and increase the final hydrocarbon recovery factors for the conditions of a particular field. Originality. The optimal value of duration of the carbon dioxide injection period at the initial gas-water contact has been determined, which is 16.32 months based on the statistical processing of calculated data for the conditions of a particular field. Practical implications. The use of the results makes it possible to improve the existing technologies for the gas condensate fields development under water drive and to increase the final hydrocarbon recovery factor.

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“…When gas-condensate reservoirs are under a bottom natural aquifer or water influx, the condensate banking will be reduced thanks to pressure maintenance. The effects of water influx in gas and retrograde condensate reservoirs have been studied in the past (Agarwal et al 1965;Ali 2014;Hower et al 1992;Izuma and Nwosu 2014;Ogolo et al 2014). Depending on the size and strength of the aquifer, the ultimate gas and oil recoveries can significantly increase in a gas-condensate reservoir (Ali 2014).…”

Section: Introductionmentioning

confidence: 99%

A case study of gas-condensate reservoir performance under bottom water drive mechanism

Tran

Truong

Ngo

et al. 2018

J Petrol Explor Prod Technol

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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.

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Recovery Optimization in a Multi-Reservoir Offshore Gas Field With Water Influx

Cited by 10 publications

References 4 publications

Optimization of Gas Recovery using Co-production technique in Water Drive Reservoir

Optimization of Gas Recovery using Co-production technique in Water Drive Reservoir

Studying the influence of the carbon dioxide injection period duration on the gas recovery factor during the gas condensate fields development under water drive

A case study of gas-condensate reservoir performance under bottom water drive mechanism

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