Injection Non-Hydrocarbon Gas Injection into Reservoir
4.0 Literature Review
4.1 Background on Primary, Secondary and Enhanced Oil Recovery
Several research studies have been conducted to find out the outcome of injecting CO2 and N2 into a porous media. The studies reveal that several and strong physical and chemical processes ought to be undertaken through multiphase flow. The flow process applies kinetics, solute transportation, hydrodynamic instabilities, viscous fingering, and capillary effects in order to allow upward moments of CO2 and N2 due to gravity override. Ultimately, the injection of non-hydrocarbon gas involves interacting fluids through an absorbent medium. The medium leads to changes in permeability, porosity, and storage capacity of the reservoir rock. The retrieval processes involves both primary and secondary recoveries (Mahendra 2).
Primary recovery refers to retrieval of natural non-hydrocarbon gas from reservoir. The process involves the gas being pushed from pore spaces into a wellbore through natural reservoir pressure and/or gravity drive. This process combines artificial lift techniques or basic pumps in order to bring the oil to the surface. Conversely, secondary recovery refers to application of techniques augmenting the retrieval process. The secondary recovery process augments natural energy of the reservoir rock by injecting water and/or gas fluids in order to force oil to flow into either wellbore or/and the surface. Thus, the oil is swept towards production wells to enhance productivity while restoring and maintain reservoir pressure (Mario and Robert 4).
4.2 Fundamental of Non- Hydrocarbon Gas Injection into Reservoir
The process of injecting non-hydrocarbon gas into a reservoir involves identifying the products in certain layers of a rock. The reservoir rock ought to meet and fulfill the following qualities. Foremost, it ought to have porosity or measure of the openings in the rock in order for the non-hydrocarbon gas to exist. Thus, the solid rock should have microscopic tiny openings called pores. The reservoir should also be permeable. The pores should be interconnected to allow non-hydrocarbons to move through the pores hence, flow into a well. The United States Energy Independence and Security Act of 2007 passed a public law legislating that; geologic storage resources ought to be available and accessible (SPEI 1).
Thus, an oilfield ought to be identified, developed and produced using primary recovery mechanisms containing natural gas in a reservoir rock. The process should also involve expansion of dissolved gases in order to change the rock volume, gravity, and aquifer influx. This ensures non-hydrocarbon gas from a reservoir rock move through the pores under pressure into a well as fluid. The fluid however is a mix of water, gas, and oil. Thus, the primary oil recovery process should range between five and twenty percent of the original oil-in-place (OOIP). Secondary oil recoveries are applied in order to improve low recoveries as they provide additional energy into the reservoir. Through secondary recovery, water and natural gas are injected in order to add and maintain pressure displace the oil. A higher production rate further extending the productive life of the reservoir rock is sustained. Ultimately, primary and secondary recoveries ought to range between twenty and forty percent of the OOIP. It also possible the range can be higher between thirty five and forty five percent of the OOIP especially at the secondary recovery (Petroleum MPG 1).
4.3 Mechanisms of each Non-Hydrocarbon Gas
In order to understand the mechanisms of non-hydrogen gases, it is crucial to differentiate between the terms miscible and immisciblity. Miscible injection refers to the economic and viable process of increasing oil recovery from diverse types of reservoirs. Co2 and nitrogen are utilized as solvents in order to increase oil recovery. Thus, miscible non-hydrogen gas injection can be used to achieve high oil saturations especially near the lower permeability strata bypassing both CO2 and N2 solvents. This is because miscibility involves injecting non-hydrogen gases that cannot form interfaces or two phases in order to displace and oil (PE 1).
Conversely, immiscibility injection refers to use of hydrocarbon gases in order to maintain pressure in the reservoir. When there is readily available supply of gas, the reservoir is filled with hydrocarbon gas into existing caps in order to overlay producing columns. The migration of oil into gas cap however has to be prevented while increasing the recoveries. Ultimately, immiscibility injection involves under-saturated solvents in order to swell the oil and increase oil recovery. Thus, it partially or completely maintains pressure in the reservoir in order to displace oil vertically or horizontally for recovery (SPE 1).
4.3.1 Mechanism of CO2
There are various mechanisms applied to keep CO2 securely stored. The first mechanism refers to structural or stratigraphic trapping. It is the most dominant mechanism. Supercritical CO2 when injected becomes buoyant than other liquids within the pore spaces ensuring it percolates upwards through the rocks. When the gas reaches the top, it meets an impermeable layer of the reservoir rock allowing the trapping process. The second mechanism is known as residual trapping. It happens quickly as the porous rock is often applied as a tight and rigid sponge like medium. Supercritical CO2 is therefore injected into the formation in order to displace fluids until it moves through the porous rock. Some CO2 is however left behind as residual droplets in the pore spaces. The residual droplets are immobile like water in a sponge. This process of trapping therefore allows CO2 to be held for several years (CPP 1).
The third mechanism refers to solubility trapping. It can be compares to the process of dissolving sugar in tea. CO2 therefore dissolves into other fluids in its gaseous form into a supercritical state. When CO2 dissolves into salt water or brine present in porous rock, the fluid becomes denser than the surrounding fluids. As a result, it sinks to the bottom of the porous rock with time. Consequently, it continues to trap more CO2 in a more secure process. The final mechanism is known as mineral trapping. It refers to the final phase of injecting CO2 after it dissolves into water to form a weak carbonic acid. As the process continues to take place, the weak carbonic acid reacts with minerals surrounding the rock until solid carbonate minerals are formed. This can take place either in a rapid or very slow pace as it depends on the chemistry of the rock and water in specific storage sites. Ultimately, CO2 is bided effectively to the rock over millions of years at different rates allowing geologic storage (CPP 1).
4.3.2 Mechanism of Nitrogen
Modern industrial developments have allowed recovery of neglected gases and oils including nitrogen. Enhanced oil recovery has been aiming to increase reserves and production. The main mechanism therefore involves non-thermal recovery, which is further divided into other techniques. The first technique involves maintenance of pressure, as it is a more complete process in retrieving nitrogen using special technological methods. Though artificial maintenance of formation pressure, oil recovery increases by injecting fluid into the reservoir. This delays the pressure from declining during production hence, increasing the amount of economic nitrogen retrieved. The second technique involves waterflooding. After pressure declines due to injection of water into the wells, nitrogen is pushed upwards into the producing wells. Thus, this technique involves pumping water into productive layer at injection pressure through boreholes. The volume ought to be equal or greater that the volume of nitrogen to be recovered. Ultimately, formation of nitrogen in the deposit is maintained at optimum level prolonging the lifetime of the well, reducing amount of drilling operations, and the cost of recovery (Bandar 1).
Gas injection is also a mechanism applied in recovering nitrogen. It can apply miscible and immiscible gas injection at or above Minimum Miscibility Pressure (MMP). This causes nitrogen gas to be miscible in oil. Conversely, immiscible gas injection involves flooding conducted below MMP. The low-pressure injection ensures pressure within the reservoir is maintained hence, preventing production cut-off. This further increases the rate of producing nitrogen (Mario and Robert 5).
Liquefied petroleum gas miscible is also applied as technique displacing nitrogen using miscible slug or injection of liquid solvent. The liquid solvent is miscible on first contact with residue of nitrogen using a slug of other liquefied petroleum gases, inert gas, water, and other natural gases. Thus, the liquid solvent banks oil and water displacing nitrogen, which is recovered. High-pressure lean gas miscible process on the other hand involves continuous injection of high-pressure nitrogen into the reservoir. Through multiple contacts with the reservoir oil and lean gas, a miscible bank is formed. Light components of condensed nitrogen inject gas into the oil until they are stripped into the lean gas phase (SPEI 1).
4.4 Factors affecting Non-Hydrocarbon Gas Injection
There are various factors affecting non-hydrocarbon gas injection. As discussed earlier, measure of the openings in the rock as well as interconnection of pores to allow non-hydrocarbons to move through the pores or permeability affect gas injection. Other factors include wettability, which refers to the tendency of a fluid to spread to a solid surface while other immiscible fluids are present. The flow of two immiscible fluids in a porous media therefore relies on wettability. This is because wettability of reservoir rocks determines how non-hydrocarbon gases will be distributed in the porous medium. For example, when the wetting phase is filled up with smaller pores while non-wetting phase occupies bigger pores, distribution of the non-hydrocarbon gases affects the recovery process. Thus, if the surface of the reservoir rock is wet, the water occupies smaller pores. Consequently, it wets the surface of the bigger pores. The occupation of water on smaller pores forces oil and gas from those pores. The rock surface however can also be wet from oil. Oil tends to spread to smaller pores hence, displacing water. This incidence poses challenges in recovery of non-hydrocarbon gases and oil (Bandar 1).
The quality of reservoir heterogeneity also affects non-hydrocarbon gas injection. Reservoir heterogeneity refers to the variation in reservoir properties as a function of space. The efficiency and effectiveness of recovering non-hydrocarbon gas from the reservoir therefore depends on how well the layers communicate with each other. Effective communication occurs when barriers to fluid flow such as lateral farcies variation, faults, lenses and unconformities are eliminated. Various companies tasked in recovering gases and/or oil recognized that, enhanced oil recovery projects failure or face difficult challenges due to reservoir heterogeneity. It is therefore important to ensure that, embarking on any enhanced oil recovery project should involve gathering essential facts for a better understanding of the reservoir size, shape and heterogeneity. This recommendation can be achieved by conducting interference tests and pressure history analysis on the reservoir (Petroleum MPG 1).
4.5 Reservoir Characteristics: Fluid Properties
Water in a reservoir is presented during the time of discovering non-hydrogen gases. The oil in the reservoir forms through condensation of volatilization when pressure is released. The mechanisms of releasing energy provide operations of drilling wells to reduce pressure in the reservoir. This leads fluids to expand hence, inducing production and flow movements of the liquids. Net volume of an expansion rock and fluids within reservoir results to an equal volume of displaced fluids. Water bearing reservoirs called aquifers can therefore be adjoined to petroleum reservoirs. When the aquifers expand, an overflow of water into the petroleum reservoir occurs. This results into an equal volume of fluid expulsion from the reservoir. Gravity segregation however does not directly result into fluid expulsion. Instead, it causes the oil to settle at the bottom allowing gas to migrate to the top area of the reservoir. A skilled operator should therefore be tasked with recovery of oil using selective recovery mechanisms (SPEI 1).
The main fluids during injection are therefore water and gas. They should add energy and displace the non-hydrogen gases that ought to be recovered. As a result, it should be noted viscosity is the most important fluid property in enhanced oil recovery projects. This is because it controls the flow of fluids in the reservoir (Terra 1). Thus, viscosity refers to the resistance of the fluid to flow. If a liquid has a lower viscosity, the process flowing through a porous and permeable medium is enhanced easily. Conversely, if the viscosity quality of a fluid is higher, it is becomes difficult to flow through the pores and permeable medium. Thus, checking the viscosity quality of a fluid should also involve measuring the temperatures, pressure, gravity, and solubility of the non-hydrocarbon gases. After ensuring these dependents are and remain constant, a higher viscosity of non-hydrocarbon gas should translate to a higher residual saturation of the gases (Mario and Robert 20).
4.6 Injection pattern of Nitrogen and CO2 and Oil Recovery
An appropriate injection pattern is selected to ensure the process is successful. Non-hydrocarbon gas injection patterns ought to be cost effective and suitable to the geologic conditions. Sweep efficiency of CO2 and N2 involves gravity overriding the less dense solvent in the oil being displaced. The good vertical communication is more stratified hence, the most important in miscible flooding. In order to increase sweep efficiency, the well spacing should be reduced, injection rate increased, and well patterns reconfigured. The solvent bank sizes should also be increased and the ration of water being injected to the solvent modified.
4.7 Advantages and Disadvantages of Injection Non-Hydrocarbon Gas
CO2 presents two advantages. Foremost, the gas provides additional recovery opportunities. This promotes energy dependency. Consequently, CO2 is stored at reduced atmospheric pressure in order to allow emission. Injecting CO2 and N2 into depleted fields can therefore be attractive as it facilitates production of more hydrocarbons. This is crucial in maintenance of pressure hence, increasing oil recovery process. Consequently, storage costs are reduced as the buffer capacity depends on the balance of incoming gas and the utilization process. Unfortunately, the oil recovery process relying on displacement has to involve several mechanisms including direct miscible displacement of oil. Thus, a higher permeability pore path should allow oil to bypass the pore levels. Consequently, it can be recovered through oil swelling occurring as solvent dissolves in the oil. This accounts for at least twenty to thirty percent incremental recovery of oil (Larry and Mark 6).
4.8 Parameters to Consider when Selecting the Non-Hydrocarbon Injection
Relative permeability with remaining fluid saturation values after displacement is crucial as they improve and increase recovery. For example, when CO2 is mixed into oil the properties change as it becomes thicker and quick to flow. Thus, alteration in residual fluid saturation before and after the non-hydrocarbon gases are injected relies on the flow and viscous properties. Gravitation refers to the natural phenomenon through which objects with mass attract. It is therefore a fundamental force of physics. The non-hydrocarbon gas injection process however considers the gravity forces as negligible. This is because of the surface tension between molecules of liquids through intermolecular forces. The surface tension therefore ensures the gases are pulled all over leading to a net force zero. As the gases continue to be pulled inwards and deeper into the liquid, CO2 and N2 molecules are not intensely attracted to the neighboring medium until they have an effect of the fluid getting displaced. Thus, CO2 and N2 can undergo miscible and immiscible displacement simultaneously (SPE 1).
Capillary action refers to a major impact on the injection system as it directly influences the ability of CO2 and N2 to be drained into the oil that is displaced. It occurs when adhesive intermolecular forces between CO2 and N2 gases as well as oil are stronger than cohesive intermolecular forces inside. This causes a concave meniscus to form. Thus, CO2 and N2 can be injected for an hour in order to increase the recovery ration when they are mixed at different ratios. The maximum recovery percentage however has to be observed at precise values while ensuring simulation at optimum recovery rate does not change. This can ensure injection of CO2 and N2 improves up to two percent. The process of validating the fluid displacement depends on the porous medium. An incompressible and steady flow of fluid simulates the injection process. Thus, the rate of flow of gases should be equivalent to the result of permeability medium, cross-sectional area, and the pressure or dynamic viscosity (SPE 1)
5.0 Works Cited
Bandar, Duraya. Enhanced Oil Recovery Techniques and Nitrogen Injection. King Saud University, 2007. Web 1st July 2015: http://csegrecorder.com/articles/view/enhanced-oil-recovery-techniques-and-nitrogen-injection
Carbon Dioxide Capture Project (CPP). CO2 Trapping Mechanisms. Phase Four Participating Organizations, 2015. Web 1st July 2015: http://www.CO2captureproject.org/CO2_trapping.html
Larry, Lake, and Mark, Walsh. Technical Report: Enhanced Oil Recovery (EOR) Field Data Literature Search. Department of Petroleum and Geo-Systems Engineering University of Texas, 2008. Web 1st July 2015: http://www.ens.dk/sites/ens.dk/files/undergrund-forsyning/olie-gas/felter-produktion-danmark/foroeget-indvinding-eor/EOR_Report_Final.pdf
Mahendra, Verma. Fundamentals of Carbon Dioxide-Enhanced Oil Recovery (CO2-EOR): A Supporting Document of the Assessment Methodology for Hydrocarbon Recovery Using CO2-EOR Associated with Carbon Sequestration. United States Geological Survey, 2015. Web 1st July 2015: http://pubs.usgs.gov/of/2015/1071/pdf/ofr2015-1071.pdf
Mario, Farias, and Robert, Watson. Interaction of Nitrogen/CO2 Mixtures with Crude Oil. Department of Energy and Geo-Environmental Engineering, Pennsylvania State University, 2007. Web 1st July 2015: https://www.netl.doe.gov/File%20Library/Research/Oil-Gas/Natural%20Gas/2005PSU.pdf
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