CGE567 Reservoir Engineering I UITM Assignment Sample Malaysia

CGE567 Reservoir Engineering I is a course offered by the Universiti Teknologi MARA (UiTM). This course is designed to provide students with a comprehensive understanding of the fundamental principles and concepts of reservoir engineering. As a student, you will learn about the various aspects of reservoir engineering, including reservoir rock properties, fluid properties, well testing, and production forecasting.

Through this course, you will gain an understanding of the various methods used to analyze reservoir behavior and performance. You will also learn about the various techniques used to optimize production from oil and gas reservoirs. This course will equip you with the necessary knowledge and skills to excel in the field of reservoir engineering.

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In this section, we are discussing some assigned tasks. This includes:

Assignment Task 1: Describe the fundamental of resevoir rock and fluid properties in term of their interaction, fluid flow, and accumulation in porous media.

Reservoir rock and fluid properties play a crucial role in the behavior of fluids in porous media, which is critical to the successful exploration and production of hydrocarbons.

Porous media, such as rocks, contain pores and fractures that can hold fluids such as oil, gas, or water. The properties of the reservoir rock, such as porosity, permeability, and pore size distribution, control the amount of fluid that can be stored and the rate at which it can flow through the rock.

Porosity refers to the percentage of pore space in the rock, while permeability is a measure of how easily fluid can flow through the rock. In general, rocks with higher porosity and permeability are better reservoirs for oil and gas, as they can hold larger amounts of fluids and allow for higher flow rates.

Fluid properties, such as density, viscosity, and compressibility, also play a critical role in reservoir behavior. Density is the mass per unit volume of the fluid, while viscosity is the fluid’s resistance to flow. Compressibility is a measure of how much the fluid volume changes under pressure.

The interaction between reservoir rock and fluid properties determines the behavior of fluids in the reservoir. For example, when fluids are injected into the reservoir, they can displace existing fluids, leading to the accumulation of hydrocarbons in certain areas of the reservoir. The rate at which fluids flow through the reservoir is also influenced by the interaction between the properties of the fluid and the rock.

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Assignment Task 2: Analyse the fundamental of reservoir rock and fluid properties in term of their interaction, fluid flow, and accumulation in porous media.

Reservoir rock and fluid properties play a crucial role in the exploration and production of hydrocarbons. The interaction between the reservoir rock and the fluid in the porous media determines the fluid flow and accumulation. In this analysis, we will discuss the fundamental of reservoir rock and fluid properties in terms of their interaction, fluid flow, and accumulation in porous media.

Reservoir Rock Properties:

The properties of the reservoir rock, including porosity, permeability, and capillary pressure, determine the ability of the rock to store and transmit fluids.

  1. Porosity:

Porosity is the measure of the void space in the rock, which can be filled with fluids. Porosity is the primary factor that controls the storage capacity of the reservoir rock. Porosity can be calculated by dividing the volume of void space in the rock by the total volume of the rock.

  1. Permeability:

Permeability is the measure of the ability of the rock to transmit fluids through the interconnected void space. Permeability is a function of the pore size, pore shape, and the connectivity of the pores. The permeability of the rock determines the rate at which fluids can flow through the reservoir.

  1. Capillary Pressure:

Capillary pressure is the pressure difference between the fluid in the pore space and the fluid at the surface of the rock. Capillary pressure is a function of the contact angle between the fluid and the rock surface and the pore size. Capillary pressure affects the fluid flow in the reservoir and can cause fluids to be trapped in the pore spaces of the rock.

Fluid Properties:

The properties of the fluid, including viscosity, density, and compressibility, determine the fluid flow behavior in the reservoir.

  1. Viscosity:

Viscosity is a measure of the resistance of the fluid to flow. High viscosity fluids are more difficult to flow through the pore spaces in the reservoir rock, while low viscosity fluids flow more easily.

  1. Density:

Density is a measure of the mass per unit volume of the fluid. The density of the fluid affects the buoyancy forces that drive fluid flow in the reservoir.

  1. Compressibility:

Compressibility is a measure of the change in volume of the fluid in response to changes in pressure. Compressibility affects the pressure distribution in the reservoir and the fluid flow behavior.

Fluid Flow and Accumulation:

Fluid flow in the reservoir is driven by the pressure difference between the fluid in the reservoir and the wellbore. Fluids will flow from areas of high pressure to areas of low pressure until the pressures are equalized. The flow behavior of the fluids is determined by the properties of the rock and the fluids. Fluids can accumulate in the reservoir when the pressure in the reservoir is higher than the pressure in the wellbore.

Assignment Task 3: Evaluate the reservoir fluid properties through applications of charts, correlations and oil field standards.

Reservoir fluid properties are crucial parameters that help in characterizing and estimating the behavior of hydrocarbons in a reservoir. These properties include fluid density, viscosity, formation volume factor (FVF), and gas-oil ratio (GOR).

One way to evaluate reservoir fluid properties is through the use of charts and correlations. These tools provide a quick and easy method to estimate the properties of reservoir fluids based on measured data, such as pressure, temperature, and composition.

For example, the Standing-Katz chart is a widely used tool for estimating the gas-oil ratio (GOR) of reservoir fluids. This chart uses the reservoir pressure, temperature, and gas gravity to estimate the GOR. Similarly, correlations such as the Beggs-Brill correlation can be used to estimate the pressure drop in a pipeline or wellbore based on the fluid properties.

Oil field standards, such as those established by the American Petroleum Institute (API), can also be used to evaluate reservoir fluid properties. For example, the API gravity is a standard measure of crude oil density, which can be used to estimate other fluid properties such as FVF.

Another common approach to evaluate reservoir fluid properties is through laboratory testing, such as PVT (pressure-volume-temperature) analysis. This involves collecting fluid samples from the reservoir and subjecting them to a range of pressures and temperatures to determine their behavior.

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