Simulation Study of Underground LPG Storage in a Depleted Conceptual Oil Reservoir

Introduction

Energy storage has assumed a critical significance within contemporary energy systems. It served to alleviate interruptions in supply. Such interruptions originated from a variety of sources. One contributing factor was the limited capacity for production. Additionally, disruptions in transportation emerged as a concern. Constraints imposed on refining processes further compounded the difficulties faced. Through the establishment of a strategic reserve of energy resources, nations were able to safeguard their local requirements. This strategy also contributed to the enhancement of energy sovereignty [1]. Storage solutions were necessary throughout the petroleum value chain. They existed at different value chain. Crude oil storage was essential first. Then there were intermediate products that needed storing too. Finally, finished fuels required effective storage before ultimate consumption. In summary, effective energy storage systems ensured stability in an unpredictable environment while supporting national autonomy in energy matters [2]. Tanks are prevalent in the petroleum sector. Spherical and cylindrical configurations represent the most extensively utilized forms. For liquefied petroleum gas, two primary alternatives are available. Cylindrical and spherical structures function as repositories. Liquefied petroleum gas (LPG) is characterized as the lightest (possessing the lowest density) liquid fuel generated within a refinery. Its density is comparatively lower than that of alternate fuels. The management of this supply is imperative for economic stability. The methodologies for storage are contingent upon the modalities of storage and transportation. Subterranean storage presents numerous advantages. It appeared to be a feasible substitute for conventional methodologies. This category of storage utilized underground spaces for diverse purposes. It contributed to the conservation of surface land. Furthermore, it afforded protection against climatic conditions and various hazards. The notion gained prominence in the latter part of the 20th century. There was a growing emphasis on more efficient methods for resource storage. Traditional storage frequently encountered constraints such as spatial and security challenges [3].

There are three main methods that hydrocarbons can be stored underground:

• Mined Tunnels: These are excavated using conventional mining techniques and are suitable for liquid or liquefiable products.

• Salt Cavern Storage: This method involves dissolving rock salt to create large cavities in salt deposits. It is suitable for all liquid, gaseous, and liquefied hydrocarbons.

• Aquifers and Depleted Fields: These natural formations can be repurposed for gas or oil storage, providing a cost-effective and environmentally friendly solution [4].

Table 1: Summarizes the Different Types of Underground Storage Media and Their Characteristics

Today, liquefied petroleum gas (LPG) is extensively employed by both industrial operators and private individuals in their mobile endeavors. When combined, LPG can also function as a fuel source for vehicles (LPG-c).The primary constituents of LPG, propane and butane, exist in a gaseous state at standard atmospheric pressure (1 bar) and ambient temperature (15°C). Nevertheless, these substances can be readily converted into liquid form, facilitating efficient handling, transportation, and storage in compact volumes:

• One liter of liquid butane yields 239 liters of gas (at 15°C under 1 bar of pressure).

• Conversely, one liter of liquid propane generates 311 liters of gas (at 15°C under 1 bar of pressure).

Propane and butane exhibit variations in the temperature and pressure conditions required for their transition from gaseous to liquid states. Under standard atmospheric pressure (1 bar):

• Propane transitions to liquid state when the temperature decreases below -42°C, while butane liquefies when the temperature falls below 0°C.

• LPG fuel, comprising a mixture of propane and butane, possesses a distinct liquefaction temperature compared to its individual constituents, transitioning to liquid at - 25°C under atmospheric pressure.

In contrast, methane (CH4), the predominant component of natural gas, requires either elevated pressure (47 bar at - 82°C) or extremely low temperature (1 bar at -161°C) to achieve liquefaction. The critical point of a pure substance is defined as the location on the temperature-pressure diagram where the liquid-gas equilibrium curve terminates [5]. The critical temperature (TC) and critical pressure (PC) represent the specific temperature and pressure at which a substance transitions. The molar volume and density corresponding to these parameters are referred to as the critical volume and critical density, respectively. When the temperature and pressure exceed the critical values, no phase transition between liquid and gas occurs, and the substance is classified as supercritical. Supercritical fluids display distinctive properties, amalgamating traits of both liquids and gases, thereby rendering them advantageous for a myriad of industrial applications [6].

Materials and Methods

Model Design

To construct the reservoir model, we utilized the CMG software, specifically the Builder and Imex interfaces. To simplify the model, several assumptions were made:

• Temperature Effects: The influence of temperature on reservoir properties was neglected.

• Rock Compressibility: Rock compressibility was assumed to be constant.

• Injection and Production Operational and Monitoring Variables: they were set at their maximum and minimum allowable.

• Simulation Time step: was defined as annual.

• Water Salinity: Injected water was assumed to be non- saline.

• Gas Composition: The gas that was injected consisted of 12% ethane, 38% propane, and 50% butane.

A non-sealing fault that crosses the model was incorporated into a three-layered synthetic Cartesian grid that was constructed for the case study. The directional permeabilities in the model are varied, but the porosity was fixed as a constant at 30%. A five-spot well layout that was inverted was used in the first production plan. It is possible that the well types will need to be modified in order to achieve the remaining production, injection, and LPG storage milestones. A black oil model, which uses partial differential equations to explain fluid flow behavior, was used to simulate fluid flow. The following are the equations for the extended black oil model [7].

• Sw: Water saturation

• So: Liquid phase saturation

• Sg: Vapor phase saturation

• Bo: Formation oil volume factor

• Bw: Formation water volume factor

• Bg: Formation gas volume factor

• Rs: Ratio of gas solution in oil phase

• Rv: Ratio of vaporized oil in gas phase

Figure 1: Typical Phase Diagram of Black Oil

Figure 2: Relationship between Solution Gas Ratio, Formation Oil Volume Factor and Pressure

Figure 3: Relationship Between Oil and Gas Viscosity as Function of Pressure

Figure 4: Relationship Between Relative Oil and Water Permeability as Function of Water Saturation

Figure 5: Relationship Between Relative Permeability of Oil and Gas as Function of Liquid Saturation

Figure 6: Ternary Plot of Water, Oil and Gas Saturation

Figure 7: Distribution of Vertical Permeability

Figure 8: Distribution of Horizontal Permeability

Figure 9: Declination Curves According to the Drive Mechanism

                                  Table 2: Reservoir Parameters

Primary and secondary recovery operations were simulated on 14 years. Initially, the reservoir contained no free gas due to its pressure being above bubble point pressure.

Figure 10: Initial Oil Saturation

Figure 11: Initial Gas Saturation

Gas Injection, Storage, and Production

A 40–70% recovery was anticipated after secondary recovery, enabling LPG infusion. The volume needed to sustain reservoir pressure is known as the base gas, which is made up of both injected and native gas. The amount injected and withdrawn during typical storage cycles is known as the working gas, which makes up 70% of the total gas [8]. The gas-water front shifts as a result of edge water being displaced by the creation of a gas bubble. The Buckley-Leverette theory explains this displacement mechanism. Three stages are involved in the creation of gas bubbles, as Figure 12 shows.

Figure 12: Formation of a Gas Bubble; De Muller-Kirschbauer; [18]; Chapter 6; Slide 42

                                                                Table 3: Schedule of Injections, Rest and Production Operations

Results & Discussion

Primary Recovery

The reservoir produced a total of 28,871 MSTB of oil, 264,779 MMSCF of gas, and 35,336 MSTB of water during the natural depletion period. As a consequence, the reservoir contained 229,684 MSTB of oil, 63,473 MMSCF of gas, and 105,603 MSTB of water. With 12% oil and 80% gas, the hydrocarbon recovery percentage was 46%. During production, the reservoir pressure dropped dramatically and got close to the bubble pressure. In the reservoir, gas saturation rose noticeably [9].

Figure 13: Distribution at the end of the Primary Recovery of Gas Saturation

                   Figure 14: Oil saturation at the end of Primary Recovery

Secondary Recovery

After primary recovery, 54% of hydrocarbons remained in the reservoir. Water injection through wells wl3 and wl4 was implemented to sweep remaining oil towards the producer. Water injection led to a rapid decrease in gas saturation. Over five years, 3,090 MMSTB of water was injected, resulting in a total hydrocarbon recovery of 64%, an 18% improvement over primary recovery (41% oil and 81% gas) [10].

                       Figure 15: Oil Sweeping by Water

Gas Injection, Storage, and Production

Over 64% of the hydrocarbon reserves in the reservoir were produced, an estimated 108.6 MMSTB of oil and 286,288 MMSCF of gas were extracted. In all, 2,708 MMSTB and 3,092 MMSTB of water were generated and injected. At standard pressure settings, this implies a 284,593 MMSCF storage potential. Considering the compressibility characteristics of the gas alongside the elastic properties of the reservoir, an increased volume of gas may be introduced. The occurrence of fractures in the cap rock may arise from elevated pressure within the reservoir, which could subsequently threaten the overall stability of the reservoir [11].

Gas Injection (4 wells)

After water injection, an increase in reservoir pressure was observed. The pressure distribution differed from water injection due to the diagonal well placed. Water injection resulted in a pressure increase from injectors towards the center, reflecting water mobility. Gas injection through four wells led to a more homogeneous pressure distribution. Gas saturation remained relatively unchanged, suggesting two possibilities:

• Injected gas dissolved in residual oil.

• LPG remained in the liquid phase, treated as oil by the simulator.

Figure 16: Oil Saturation After Injection

Rest and Observation

During the resting period, pressure, bubble pressure, and gas saturation remained stable. However, a slight increase in oil saturation was observed, possibly due to gas dissolution into the oil phase. To release dissolved gas, reservoir depressurization would be necessary to reduce bubble pressure [12].

Figure 17: Bubble Pressure Distribution After Gas Injection

Production by the Central Well

To depressurize the reservoir, the central well was opened, leading to oil migration towards the depressurization zone. This reduced bubble pressure in oil-saturated zones and resulted in a significant release of dissolved gas.

Figure 18: Oil Saturation

Figure 19: Bubble Pressure

Periodic Production of the Central Well (50%)

To maintain gas release, the central well was kept open 50% of the time. This led to a decrease in oil saturation and an expansion of free gas in the upper reservoir layers.

Production by Central Well

Bubble pressure decreased, leading to gas release and improved gas saturation.

Production and Periodic Injection from Central Well

Periodic injection and production resulted in increased gas saturation and significant gas expansion at the surface. Oil accumulated in the lower layers, particularly near the central well.

Figure 20: Gas Saturation in 2040

Central Production and Rest

Reservoir pressure decreased due to central well production. The resting phase aimed to assess gas expansion slowing. However, oil migrated from lower layers to the surface, changing phase.

Gas Injection by the 4 Wells

A second injection phase was conducted to evaluate gas dissolution and free gas behavior. Injection increased reservoir pressure, facilitating gas dissolution and limiting free gas expansion. Bubble pressure increased significantly in the upper layers

Figure 21: Distribution of Bubble Pressure in 2050

Figure 22: Oil Saturation in end Stage

Production by the 4 Wells

Oil reserves that were kept close to the injectors were produced as a result of simultaneous production from all operating wells. Gas saturation was rising as oil collected close to producer 2. Reservoir pressure and bubble pressure both decrease significantly [13].

In order to ascertain which theory about gas dissolution was right, Figures 23 and 24 were examined.

Figure 23: Gas Production From Wells

Figure 24: Oil Production From Wells

The simulator’s treatment of LPG as oil indicates that it remained in the liquid phase underground, as indicated by the model’s increasing gas saturation and the notable drop in gas production. The LPG gas phase, which can be viewed as losses because of its growth restricting storage capacity, is represented by the measured gas saturation [14].

Conclusion

The approach established in this work examined the effectiveness of LPG storage in depleted petroleum deposits and examined the fundamental mechanisms controlling gas flow and storage. Gas production and storage were conducted after primary and secondary recovery procedures to ascertain the best storage conditions. The following are the main conclusions of this work:

• Liquid Phase Storage: Until the LPG bubble point pressure is not achieved, LPG stays in the liquid phase in the reservoir. For LPG storage to be successful, reservoir pressure monitoring is therefore essential for controlling the LPG phase [15].

• Multi-Phase Production: Light oil, water, and gas make up the mixture that is created [16].

• Production Difficulties: Production abandonment may result from damage to reservoir structures, excessive water production, and pressure decline [15].

• Pre-Injection Studies: Laboratory experiments should be run to evaluate rock-fluid interactions between the reservoir, formation fluids and injected fluid. This could help to predict for instance miscibility occurrences and capillary changes after LPG injection [17].

• Versatility: Underground reservoirs could be used to store different kinds of gas [18].

• Long-Term Planning: Successful implementation requires extensive reservoir studies and planning to establish optimal production and injection scenarios.

• Well Configuration: Multiple injectors per producer can maintain pressure balance, promote fluid migration, and limit degassing. A control well and water injector should be maintained for reservoir purging [19].

Underground storage in porous media offers substantial potential for repurposing abandoned oil formations into storage facilities for natural gas, liquefied petroleum gas, carbon dioxide (COâ??), or methane. These formations vast storage capacity and resistance to mechanical deformation have contributed to their widespread adoption [20-44].

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