Water injection has proven to be one of the most successful, efficient and cost-effective reservoir management strategies. By reinjecting treated and filtered water into tanks, this approach can help maintain tank pressure, increase hydrocarbon production, and reduce environmental impact. The goal of this project is to create a water injection model using Eclipse tank simulation software to better understand water injection methods to maintain tank pressure. A basic reservoir model is utilized in this investigation. The simulation was performed about 52 years using ECLIPSE Reservoir simulator. In all cases, result shows that oil production with water injection is higher compared with the base case. With this, it would be preferred to apply waterflooding for oil recovery in depleted reservoirs to the use of primary methods. It is also observed that water breakthrough is earlier and water production increases gently with water injection rates. Sensitivity on the injection rate using the 3D model showed that the injection rate has impact on the process. The pressure increases with high injection water rate in all cases. Despite higher reservoir pressure and early in water breakthrough, water flooding accounts for less oil recovery due to rapid water production. Generally, based on the results and discussions, it can be concluded that the water injection option can be used to increase the reservoir pressure to a good extent. 

Identifying the driving mechanism and PVT analysis is important for optimizing reservoir development plans through primary, secondary, or tertiary recovery methods. Also, determining the size of an aquifer (based on its response to pressure support) provides a means of calibrating known physics against production data, which once calibrated can be used for prediction. In this paper, the types of natural drivers of the reservoir were estimated and compared using a program called MBAL after matching production history data with model results. The purpose of this paper is to evaluate the basic driving mechanisms and PVT analysis using MBAL software for Intisar D field. The final project results can be seen matching the real data of the reservoir with the program results using MBAL software. The simulation results show that the reservoir pressure history curve matches the stimulation curve, and this gives a good indication of the input data fed into the model. The driving mechanism for all these tanks comes from three natural forces, namely fluid expansion, compression, and water flow. It started with the expansion of the fluid from 0 to 0.60, with the compressibility from 0.60 to 0.89, and with the flow of water from 0.89 to 1 is the flow of water.

The main goal of this study (which the comprehensive reservoir study for Libyan X Field plan of development) is to predict future performance of a reservoir and find ways and means of optimizing the recovery of some of the hydrocarbon under various operating conditions. The simulator results show the reservoir pressure history curve is matching to the stimulation curve, this gives a good indication of the input data that has been entered to the model. The driving mechanism for all those reservoirs it comes from three natural forces, which are fluid expansion, PV compressibility, and water influx. The best method to choose as secondary recovery for this oil field is water and gas Injection. Water and gas Injection have the largest Total Field Recovery. Water and gas Injection have the highest Reservoir Pressure at the end of the project. The highest percentage of oil recovery was when the water and gas were injected and it reached 58%, then when the water was injected and it reached 55%, and then when the gas was actually injected and it reached 54%. The field pressure rise was greater when water and gas were injected, and the pressure reached 792 psi, while it was less when only water was injected, reaching 435.5 psi, and when only gas was injected, it reached 412.9 psi. Finally, central objective of this master thesis with the help of reservoir simulation fulfilled to produce future prediction that will lead to optimize reservoir performance which meant reservoir developed in the manner that brings utmost benefit to the commercial business.

A type of EOR, secondary production includes water flooding and gas injection. Normally, gas is injected into the gas cap and water is injected into the production zone to sweep oil from the reservoir. A pressure-maintenance program can begin during the primary recovery stage, but it is a form of enhanced recovery. The main purpose of this report is to investigate the effect of the reservoir rock compressibility on oil recovery factor during gas injection. The problem statement of this study is firstly, as the reservoir oil and gas production under primary conditions, causes the reservoir pressure to decline. Secondly, A gas injection is required to re-energize or “re-pressurize" the reservoir. The main objective of this project is to investigate the effect of the reservoir fluid densities on oil recovery factor during gas injection. By using ECLIPES Software, we model the data and find out the best prediction of gas injection that is suitable for the available field data. It is proven that the optimum oil production is by injection a high amount of injection rate. The highest increase in percentage of the total gas production is when an injection of 54 MMSCF is 0.58 %. The higher the compressibility value of the rock, will give the higher the rate of oil and gas production. The relationship between oil rate, gas rate, pressure, and oil recovery factor are directing the compressibility of rocks is a direct relationship.

This paper examines on the effect of the reservoir rock permeability on gas injection by using reservoir simulation. This task will be performed by using reservoir simulation software (Eclipse). This injection interacts with CO2 to create conditions favorable for oil recovery. The main target of this project is to investigate the effect of the reservoir rock permeability on gas injection and the optimum injection rate to get the optimum recovery. The problems statement of this study is: As the oil and gas in a formation is produced, the hydrocarbons remaining in the reservoir may become trapped because the pressure in the formation has lessened, making production either slow dramatically or stop altogether. Climate change refers to long-term shifts in temperatures and weather patterns. Burning fossil fuels generates greenhouse gas emissions that act like a blanket wrapped around the Earth, trapping the sun’s heat and raising temperatures. Examples of greenhouse gas emissions that are causing climate change include carbon dioxide and methane. The result of effect of the reservoir rock permeability on gas injection by using reservoir simulation shows that with the increase in the permeability of reservoir rock, the rate of gas production increases. The greater the permeability of rocks, the rate of water production increases, which is a direct method relationship between water production and permeability. We note after this evaluation that the cumulative oil, water, and gas production increases with the increase in rock permeability.

  Reservoir performance prediction is important aspect of the oil & gas field development planning and reserves estimation which depicts the behavior of the reservoir in the future. This project is conducted in order to integrated production modelling with MBAL software to define the water influx model and its properties of an aquifer for Libyan oil reservoir. The objectives of this project are to determination the PVT of oil, gas, and water. Determination drive mechanism, identification of suitable water influx model and unknown parameter calculations. Define water influx using influx model. Define properties of an aquifer. Material balance software is used as principal method in order to achieve the objectives of those objectives. Based on the Material balance software results, the main source of energy in reservoir was from Water influx, pore volume, and fluid expansion drive mechanism. At the begging, the fluid expansion is from 0 to 40 % and pore volume compressibility is from 40 % to 64 % and the water influx is from 64 % to 100%, after that we has water injection. The model for this reservoir is the Hurst-van Everding-Odeh with the system is radial aquifer. Finally, central objective of this paper with the help of reservoir simulation fulfilled to know the water influx model and its properties and to produce future prediction that will lead to optimize reservoir performance which meant reservoir developed in the manner that brings utmost benefit to the commercial business.

In this study, two software MBAL - Petroleum Experts and Eclipse are used to do comprehensive reservoir study for LCSF plane of development, this study covered analyses and evaluation. Gas injection essentially increases the rate of oil field development and in many cases permits increased oil recovery. This paper demonstrates a successful simulation case study based on a field data of a project. The objective of this study is to improve recovery from Libyan Carbonate Sedimentary Field by three wells of gas injection. To do that, first, the simulation 3-D model was built by using advanced reservoir simulation software (Schlumberger Eclipse). Second, select the best zone for gas injection. Third, select the best location for injector well. Fourth, determine the injector well depth. The results of the paper can be seen to match the real data of the reservoir with the results of the program using a MBAL software. The simulator results show the reservoir pressure history curve is matching to the stimulation curve, this gives a good allusion of the input data that has been entered to the model. The driving mechanism of this reservoirs it comes from three natural forces, which are fluid expansion, PV compressibility, and water influx. Gas injection scenario has a good plateau bpd lasts approximately 3 years and after that started to decrease. The Cumulative oil production is 108442340 STB barrels of oil with the recovery factor approximately 0.52805 and final reservoir pressure is maintained 328.76 pisa            

Produced water from carbonate reservoir can be reinjected into the formation to stimulate hydrocarbon production in aging wells. This is known as water injection or water flooding. This is the most economically friendly method of produced water disposal. In this paper, a laboratory approach to compare and evaluate the efficiency of formation and sea water injection for enhancing oil recovery at room condition in carbonate reservoirs. The main objective of this paper to achieve the maximum oil recovery for the limestone rock by using formation and sea water. This study was conducted using several samples of limestone rock saturated with oil by placing them in the reservoir conditions by placing them in a vacuum oven to ensure complete saturation of the samples with oil and then extracting the oil from them using liquid permeability where the samples are injected by formation and sea water. The oil recovery by formation water injection is range from 26.4 % to 47 %. The oil recovery by sea water injection is range from 0.00 % to 10 %. The oil recovery factor for formation water injection is higher than the oil recovery factor for sea water injection.

In the life of oil production can defined into three steps, primary, secondary, and tertiary. Primary recovery can include natural mechanisms such as rock expansion, gas cap, and solution gas, secondary recovery that use injection water or gas to maintenance reservoir pressure, enhanced oil recovery (tertiary recovery) that include injection special materials that is chemicals fluids, gas injection, and polymer injection. In this research use done Arabic gum as polymer flooding by using Gaberoun Water Leak & distillate water as soluble material and to make a comparison between two different water, use done three scenarios of the Arabic gum concentration, the first scenario Arabic gum with a concentration of 1%wt, the second scenario Arabic gum with concentration 3%wt and the third scenario with 5%wt. Imbibition test done used for this study by using Sandstone core samples aged in oil for a long time period reach about 3 weeks, the results of Recovery is obtained in oven temperature from 30℃ to 70℃. The oil recovery results are not very good as oil recovery by using Gaberoun Water Leak without any change on sandstone core samples, in this research reach to about 65, 62, and to 74 for 1wt%, 3wt% and 5wt% Arabic gum with Gaberoun Water Leak.