Also, it is essential not to perforate if well is near to gas water contact, the horizontal wells should be located at maximum distance from gas water contact to maximize gas recovery. To avoid water coning, using advance completion technique such as inflow control devices (ICD), installing a down hole gauge. Therefore, from the results, producing at a high rate that has high recovery before the impact of aquifer or water has occurred to the wells, known as outrunning of the aquifer. The aquifer influx rate is seen to be increased by 69% when the aquifer volume is double. This aquifer impacts the gas recovery reduction by 19 %, with water coning radial extension of 1.7 km and peak water production rate for 16 years. There is a stronger of the aquifer from the west side, which is predictable to cause water coning than on the east side. Varying the kv/kh ratio from 0.1, 0.6 to 1 shows early water breakthrough by 6 months earlier from the base case with 0.1 hence will not delay water coning and the gas recovery is reduced by 5%. Increasing tubing head pressure from 40 bar to 100 bar result to decrease plateau length period of the gas production, low water production rate, and low gas recovery. Horizontal gas wells have a constant horizontal length of 300 m. Rate-dependent skin and mechanical skin evolution in time show that increasing non-Darcy /turbulence factor reduces the performance of the well and decreases gas recovery, the high drawdown tendency is observed before water breakthrough time. The gas recovery was observed to be low, due to the distribution of permeability layer for the horizontal wells and low productivity index (performance of the well). Varying height of perforation of the well and standoff between 30 m and 40 m will delay water coning and high recovery with more extended plateau length period. Results have shown that, locating horizontal well in East-west will have early water breakthrough and not recommended due to the impact of edge aquifer and less recovery compared to north-south and original wells orientation (northwest-southeast). This work identifies parameters that will contribute to the impact of water coning by observing the effect of water coning/cresting in horizontal gas wells and predicting the performance of these wells using Petrel simulator. The reservoir thickness also varies up to 50 m thick. The permeability distribution varies across different layers with an overall permeability of 680 mD, and porosity distribution for the reservoir varies 0.21-023. The methodologies and workflow will be discussed extensively to demonstrate how the Field team has effectively arrested production decline in the Z reservoir by proactive review and update of its wells operating envelopes.An offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. This paper will provide an overview of how the operating envelope for Producer 1 was reviewed and implemented to maximize production from reservoir Z. This provides a platform for remedial action, as any deviation from expectation is found out. Downhole velocities, drawdown, produced sand/fines data were evaluated to help mitigate completion impairment and loss of installed sand control equipments.Īn extensive post implementation analysis was also carried out to help revalidate the basis of well operating envelope. This paper presents how the operating envelops of subsea production wells in a deepwater field are being monitored and utilised as enablers to realising production targets without compromising relevant constraints such as reservoir pressure, drawdown and well integrity.Ī review of the current parameters employed to determine the required well operating envelope was carried out with a view to ascertain any window of opportunity for optimization. Operating envelopes (OE's) however, have to be kept live to reflect the dynamic nature of well performance. Well operating envelopes are defined to ensure optimal production performance, while maintaining completions integrity.
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