Increasing Oil Recovery by Gas Injection for Libyan Carbonate Sedimentary Field (LCSF) by using Eclipse Software

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


Introduction
The oil recovery process is an essential element in the oil industry, Naser et al, 2018 [1].There are many known enhanced oil recovery (EOR) methods, and every method has criteria for use.Some of those methods are gas injection, such as CO2 injection, N2 and hydrocarbon gas injection.CO2 has been the largest contributor to global EOR, Samba, et al 2020 [2].Gas injection is an enhanced oil recovery method.Inert gases, typically nitrogen or carbon dioxide, are pumped into an injection well.This creates higher pressure that filters through the reservoir formation and pushes hydrocarbons out from low pressure or isolated areas.
Cuiyu, et al, 2013 [3] used a numerical reservoir simulator to evaluate the performance of CO2 injection for the Bakken interval in a sector of the Sanish Field.Several different scenarios of gas injection are tested to analyse gas injection performance and evaluate its technical feasibility and effect.It appears that gas injection is suitable in such tight environments, as the recovery factors increased significantly for miscible CO2 injection.Baojun, et al, 1997 [4], piloted test of water alternating gas injection in heterogeneous thick reservoir of positive rhythm sedimentation of Daqing Oil Field.The study showed that the recovery factor is now more than 3% higher than the ultimate recovery factor by water injection, and the ultimate recovery is predicted to be more than 8% higher.Areal sweep conditions are improved, and the thickness of liquid production increases.Another study conducted by Hedjazi and others in 1976, [5], showed that the areal sweep conditions are improved and the thickness of liquid production is increased.
Reservoir calculations indicated that only 12.5% of the original oil in place could be recovered by normal depletion, but that recovery could be increased to 22.8% by gas injection, Hedjazi, et al 1976 [5].The early initiation of pressure maintenance by gas injection and exercising close control of producing operations will yield an ultimate recovery of approximately 70.5 percent of the original oil in place [6].
Reservoir simulation indicated that the ultimate recovery factor is expected to be over 50% with such full-field gas injection, Tang, et al 2013 [7].CO2 flooding suitability for shale oil reservoirs with low permeability, low porosity, and rich organic matter (kerogen) remains controversial [8].The simulation results show an approximately 7.5% increase in gas production and an approximately 8% increase in oil produced at a temperature of approximately 200 F, considerably higher than the 2.4% and 4% gas and oil produced at a lower injected temperature of 120 deg F, Ibe,, et al 2022 [9].The gas injection project has increased the reservoir pressure from 500 psi to 700 psi, Ariffin, et al 2022 [10].
Numerical results indicated that injection schemes based on highly slanted wells and water alternating gas injection can overcome early gas breakthrough and a considerable amount of gas emissions, providing an improved sweep efficiency, a stable displacement and a significant degree of CO2 retention, Rotelli,, et al 2017 [11].The injected gas has a negligible opportunity cost owing to sales gas export constraints.This combination of factors yields a highly economic project, Jethwa, et al 2002 [12].Nitrogen injection is being evaluated as a way to accelerate and increase oil recovery, through an improvement of the gravity drainage, main producing mechanism in this reservoir, and by pressure maintenance purposes, Arevalo-V, et al 1996 [13].During the gas injection process, the injected gas composition is changed due to the vaporizing gas drive (VGD) mechanism, in which gas is enriched with intermediate molecular weight hydrocarbons from reservoir oil Yonebayashi et al, 2009 [14].
Recent studies indicate that gas injection of the water-invaded portion of the reservoir should recover additional oil.

LCSF Basic Data
LCSF fluid and rock properties were determined by laboratory experiments performed on samples of actual reservoir fluids.Table 1 shows the LCSF data.Fig. 1 shows the effective permeability to gas and effective permeability to oil for a given gas saturation, with the oil being considered the wetting phase.Fig. 2 shows the effective permeability to water and effective permeability to oil for a given water saturation with the water being considered the wetting phase.

LCSF Fluid Data Analysis
This section will focus on the PVT analysis and production simulation of LCSF estimation by using MBAL software.The gas-oil ratio (GOR) is the ratio of the volume of gas ("scf") that comes out of solution to the volume of oil under standard conditions.When the reservoir pressure also decreases, the GOR decreases because the gas is liberated from the oil, as shown in Fig. 3.

LCSF Reservoir Potential Analysis and Depletion Analysis
This section will focus on the driving mechanism analysis and production simulation of LCSF estimation by using MBAL software.Fig. 10 shows the field gas, oil, and water production total vs time.
The Y-axis reflects the total production obtained from the gas, oil, and water wells, and the X-axis shows time.The total gas production is 1.3432202E+8 MSCF, the oil is 94873352 STB, and the total water production is 149287.33STB.shows the effect of gas production on pressure with respect to time.
The initial pressure is 3001 Psia, which decreases constantly with respect to time to 914 psia.The graph shows that the field oil efficiency is 0.46 and the field water cut is 0.00824.

LCSF Reservoir Geometry
Reservoir simulation is an area of reservoir engineering where computer models are used to predict the flow of fluids through porous media.We built reservoir models that include the petrophysical characteristics required to understand the behavior of the fluids over time.

LCSF History Matching
The act of adjusting a model of a reservoir until it closely reproduces the past behavior of a reservoir.The historical production and pressures are matched as closely as possible.Fig. 18 shows the production rate history matching results for well A60, and Fig. 19 shows the production rate history matching results for well A86.Injector Well Rate: After we know which zone we will Inject; which wells will convert and how much the bottom hole pressure target for each Injector wells.Now, we start to inject water, but before that, we must estimate the best rate of water for each well injector.To estimate the best rate, we can inject.We will play with the rate of injection for each injector well, as shown in table 2 and figure 25.Graph 32 shows the field gas injection total vs time.The time is on the x-axis, and the field gas injection total is on the y-axis.

Conclusion and Recommendation
As a comprehensive reservoir study for the LCSF plane of development, this study covered analyses and evaluation.In this project, we obtain the following conclusions:

Fig. 3 :
Fig. 3: LCSF Gas-Oil Ratio Fig. 4 shows the oil, gas, and water viscosity vs pressure.Oil viscosity increases with a decrease in the pressure under saturated conditions due to the release of dissolved gas below the bubble point.For most liquids, viscosity increases with increasing pressure because the amount of free volume in the internal structure decreases due to compression.Consequently, the molecules can move less freely, and the internal friction forces increase.

Fig. 5
Fig. 5 shows the oil, gas, and water formation volume factor.The figure shows that the formation volume factor is inversely proportional to pressure.This makes sense because as reservoir pressure declines, the gas will expand to occupy more volume in the reservoir.As we can see, Bg increases as reservoir pressure decreases.The water formation volume factor represents the change in volume of the brine as it is transported from the reservoir conditions to surface conditions.Thisshows that the oil formation volume factor increases with a reduction in pressure until the oil reaches the bubble-point pressure.The volume increase at pressures above the bubble point is due to the expansion of oil (with its dissolved gas).Below the bubble point, and with the continued reduction in pressure, the oil formation volume factor is reduced primarily due to mass loss with the additional release of dissolved gas.

Fig. 5 :
Fig. 5: LCSF Oil, Gas, and Water FVF Fig. 6 shows the oil, gas, and water density.The oil density decreases with depletion of pressure until it reaches a minimum value at the bubble point.Gas density is a function of the pressure and temperature conditions for the gas.Due to its high compressibility, gas can change its volume significantly with changes in pressure.Understanding the compressibility of formation water is also important to understanding the volumes of oil, gas, and water in reservoir rock.It is the change in water volume per unit water volume per psi change in pressure.

Fig. 7
Fig. 7 shows the reservoir pressure history and simulation vs. time for an aquiver volume of 5177 mmft 3. The history reservoir pressure curve matches the stimulation curve, which gives a good allusion of the input data that have been entered into the model.By running the simulator with historical production and comparing it with the actual reservoir performance, the reservoir pressure is matched when the reservoir aquifer volume has been adjusted to 5177 mmft 3.

Fig. 7 :Fig. 8 :
Fig. 7: LCSF Plotting Simulation Results Fig. 8 shows the comparative contributions of the main source of energy in the reservoir and aquifer system vs time.From the below Fig., the drive mechanism for this reservoir consists of the following:1.Fluid expansion ranges from 40 to 45% 2. Pore volume compressibility ranges between 45% and 55%.3.Water Influx ranges between 5 and 15%

Fig. 11 :
Fig. 11: FOE, FPR, and FWCT vs. TimeThe simulator is calibrated using historic pressure and production data in a process referred to as history matching.Once the simulator has been successfully calibrated, it is used to predict future reservoir production under a series of potential scenarios, such as drilling new wells, injecting various fluids or stimulation.Fig.12shows the LCSF reservoir model and location map.The reservoir grid is made of 57 x 46 x 56 = 146832 cells.

Fig. 12 :
Fig. 12: LCSF Reservoir Model and Location Map Fig. 13 demonstrates that the permeability variation of the first layer is altered between 0.62 and 536 mD, with an average permeability of approximately 268.31 mD .

Fig. 19 :
Fig. 19: Well, A86 Oil Production Rate History Matching results.LCSF Prediction Without any InjectionThis section will show the results of the LCSF prediction by natural reservoir energy, such as gas drive, water drive or gravity drainage, displacing hydrocarbons from the reservoir into the wellbore and up to the surface from 2013 to 2043.This scenario is called the Base Case.

Fig. 20 :Fig. 21 :
Fig. 20: FOPP, FGPP, and FWPP vs.Time (Base Case) Fig. 21 shows the field gas, oil, and water production total vs time.The Y-axis reflects the total production we obtain from the gas, oil, and water wells, and the X-axis shows time.A total of 2.2081352E+8 MSCF of gas, 1.0449847E+8 STB of oil, and 297935.25 STB of water are produced.

Fig. 22 :Fig. 23 :
Fig. 22: FOE, FPR, and FWCT vs.Time (Base Case) LCSF Secondary Recovery Injector Well Location: Secondary recovery techniques involve supplementing the natural energy of a petroleum reservoir by the injection of fluids, normally water or gas.Normally, gas is injected into the gas cap, and water is injected into the production zone to sweep oil from the reservoir, as shown in Fig. 23 and Fig. 24.

Fig. 26 :
Fig. 26: Field Gas Production Rate Scenario#1 Fig. 27 and Table 3 express the relation between the field oil potential production rate vs time from 2013 to 2043 for Scenario#1.The time on the X-axis and the field oil production rate on the Y-axis.

Fig. 27 :
Fig. 27: Field Oil Production Rate Scenario#1Graph 28 shows field pressure vs time.The time is on the x-axis, and the field pressure is on the y-axis.The graph shows that the pressure is increasing constantly with respect to time.

Fig. 28 :
Fig. 28: Field Pressure Scenario#1Graph 29 shows the field water cut vs time.The time is on the x-axis, and the field water cut is on the y-axis.The graph shows that the field water cut is increasing constantly with respect to time.

Fig. 29 :
Fig. 29: Field Water Cut Scenario#1Graph 30 shows the field oil efficiency vs time.The time is on the xaxis, and the field oil efficiency is on the y-axis.The graph shows that the field oil efficiency is increasing constantly with respect to time.

Fig. 30 :
Fig. 30: FOE Scenario#1Graph 31 shows the field oil production total vs time.The time is on the x-axis, and the field oil production total is on the y-axis.The graph shows that the field oil production total is increasing constantly with respect to time.

Fig. 33
Fig. 33 demonstrates the gas saturation distribution at the end of scenario #1 of the first layer.It is altered between 0.12 and 0.71, with an average gas saturation distribution of approximately 0.41.

Fig. 34
Fig. 34 demonstrates the oil saturation distribution at the end of scenario #2 of the first layer.It is altered between 0.06 and 0.76, with an average oil saturation distribution of approximately 0.414.

Fig. 35
Fig. 35 demonstrates the water saturation distribution at the end of scenario #3 of the first layer.It is altered between 0.12 and 0.1213, with an average water saturation distribution of approximately 0.12007.

Fig. 36 :
Fig. 36: FOPT, FGPT, and FWPT Scenario ComparisonGraph 37 shows field pressure vs. different rates.The different rates are on the x-axis, and the field pressure is on the y-axis.The graph shows the effect of gas injection on pressure.Additionally, in graph 37 shows field gas injection total vs different rates.The different rates are on the x-axis, and the field gas injection total is on the y-axis.

Fig. 37 :
Fig. 37: FPR and FGIT Scenario Comparison Graph 38 shows the field water cut vs different rates.The different rates are on the x-axis, and the field water cut is on the y-axis.The graph shows the effect of gas injection on the water cut.Additionally, in graph 38 shows field oil efficiency vs different rates.The different rates are on the x-axis, and the field oil efficiency is on the y-axis.

Fig. 38 :
Fig. 38: FOE and FWCT Scenario Comparison 1.The main reservoir driving force in the LCSF is fluid expansion.First, fluid expansion ranges from 40 to 45%.Second, pore volume

Table 1 :
Injection Rate