Figure 4-1 shows the flow history of an oil well and can be classified into three periods for. Not only that but also use of fully open choke allows much water production rate increase, which leads to water coning. 4.2 Pressure-Time History for Constant-Rate Drawdown Test. 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. While porosity and viscosity are inversely proportional to the radius of investigation.An offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. Permeability and shut-in time are directly proportional to radius of investigation. Furthermore, the study was continued to correlate radius of investigation as a function of the parameters mentioned above. This sensitivity would give various radius of investigation. Sensitivity test of several parameters namely viscosity, permeability, porosity, and shut-in time was conducted to analysis the effect of the parameters on the radius of investigation and radial flow time. Since the well test was intended to reach radial flow regime then the viscosity should be reduced from 1069 cp to 66.5 cp for production time of 500 hours or to 24.8 cp for production time of 100 hours. The study was aimed to design a proper Pressure Drawdown Test for N-7 Well using a simulator. Some kind of thermal injection should be performed prior to implementing the operation of Pressure Drawdown Test, where the heat will reduce the viscosity of the reservoir fluid. High viscosity which is an inherent property of heavy oil would give an inconclusive result on a Pressure Drawdown Test.
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