How can you evaluate well productivity and reservoir properties?

The well productivity index is valid for oil wells above bubble point and any water wells. For oil wells below bubble point and gas or gas condensate wells Inflow Performance Relationship (IPR) is used instead since the production rate dependence on drawdown is not linear as is the case for PI.

Reservoir engineering information (fluid, rock properties) and well testing data (skin, reservoir pressure, permeability estimation) are important for evaluating the productive potential of the wells. To determine the productive potential of the well a nodal sensitivity analysis was performed, by varying the value of the skin factor. Well productivity estimation is important in exploration/appraisal and development wells. Production forecast and productivity used in the field development plan and decision-making. Methos to estimate welll productivity index are: - analog method - near-wellbore modeling and simulation (1-D and 3-D static models) - near-wellbore fluid flow for productivity or production rate

It is a wide-range question. This kind of questions can’t be answered by an absolute statement. It always depends on subjectivity because different professional experience different answers. Now, if the scope of this question is to get all kinds of answers then most of these answers can be inaccurate for the same reason this question is out of range.

The Well Productivity Index (PI) gauges fluid output per pressure drop unit, reflecting well efficiency. It hinges on reservoir permeability, wellbore structure, skin factor, and fluid properties. Calculated via Darcy's law or derived from well test data, a higher PI indicates a well that yields more with less pressure loss.

The most reliable method to determine the reservoir pressure is by use of Wireline Formation Testers with single probe deploying small concentric or elongated packer that is pressed to the borehole wall. Such measurement eliminates the wellbore storage effects and allows for rapid and reliable pressure determination. When using well test data from gauges placed in the permanent or temporary completion e.g. DST, the pressure transient analysis yields initial or current average reservoir pressure by creating a proper well and reservoir model and ploting it as pressure vs. log of superposition function. Here the exptrapolation is made to infinite shut-in time to determine either the initial or current average reservoir pressure.

Reservoir pressure, vital for fluid movement to the wellbore, indicates energy, size, and depletion rate of the reservoir. It's measurable with bottom-hole gauges or inferred through pressure transient analysis from well test data, which plots pressure changes over time to deduce reservoir properties.

Reservoir pressure are measured under various conditions: - reservoir fluid pressure in the rock pores is the reservoir pressure or formation pressure. - reservoir pressure at discovery without any production is the initial reservoir pressure. It declines continuously with production when there is no support in the form of fluid injection or aquifer influx. Reservoir fluid properties change accordingly affecting recovery. - average reservoir pressure is the pressure when all production and injection activities cease and equilibrium is reached throughout the reservoir. Reservoir pressures recorded at various depths in multiple well locations are corrected to the same datum depth by using the known fluid gradient.

Wireline formation tester can give a reliable formation pressure. A direct measurement will be a single point measurement on the sandface, and will give good idea of reservoir pressure or pressure gradient especially in the good permeability zone where the effect of supercharged was less. However, reservoir pressure through pressure transient test will still be needed to upscale from single point to the average pressure across the reservoir.

Core analysis just cover a small piece of reservoir. Reservoir are heterogenous, but usually core is just taken from the best interval. Since well logs cover all interval, it will give us better picture of reservoir.

Permeability is crucial for understanding fluid flow in reservoir rocks, influencing well output and recovery. It’s measured by analyzing core samples, interpreting well logs, or examining pressure responses in well tests to determine how easily fluids can move through the reservoir.

The priority choice is core analysis for permeability estimate. Last choice is pressure transient analysis for some uncertainty.

Generating permeability from core analysis, well logs and/or from dynamics condition such as pressure transient analysis from well test was a very common methods to estimate the permeability as the key parameter for the reservoir deliverability.

Same as above, Core analysis is first priority. And It is hardly to use well test data to estimate porosity. The information mentioned here is more about theoretical but in fact there is some difference in the field application.

Reservoir porosity reflects pore volume's share of total rock volume, crucial for fluid storage capacity and influencing saturation, compressibility, and recovery. It's estimated via core sample measurements, well log property analysis, or inferred from pressure responses in well testing, defining storage potential.

Usually fluid sample is the basis of fluid properties estimation. Well logs and well test analysis using fluid properties values that comes from estimation based on fluid sample.

Reservoir fluid properties, including density, viscosity, and composition, are key to well performance and extraction efficiency. These properties are determined by analyzing fluid samples, interpreting well log data, or examining well test data through pressure transient analysis, providing insights critical for optimal reservoir management.

Reservoir fluids sampling throughout downhole fluid sampling (wireline formation testing)or recombination using fluid sampling from well test data were the common methods to investigate the reservoir fluid properties. The reservoir fluids properties are essential for further development of the reservoir models as well as the development of the field on the initial and further stages such as well deliverability, recovery factor and the proceedings of the further stage of the surface facilities on the production/development stages.

Reservoir simulation is a computational approach that models fluid flow in a reservoir, integrating key factors like productivity, pressure, permeability, porosity, fluid properties, and well operations. It predicts reservoir performance under various scenarios, aiding in the optimization of well design and management strategies.

Building reservoir simulation can take hughes amount of resources (man-hour). Rather than reservoir simulation, field development scenario can utilize analitical approach. It is common using analogues from nearby fields for primary recovery fields or nearby wells for mature field with a lot of wells.

Reservoir simulation represents an essential tool for the management of oil and gas reservoirs. A key aspect of reservoir simulation is the representation of the well in the simulator and the linkage of the well to the reservoir. This method include the requirement of a large volume of relevant data (sometimes not attainable during an exploration phase; for example it would take weeks or months to get the relative permeability and capillary pressure data), but also the time and money utilized.

Well productivity is an important factor that plays a crucial role in the efficiency and profitability of oil and gas production operations. Well productivity is a measure of how much fluid a well can produce or inject per unit of the pressure difference between the reservoir and the wellbore. A highly productive well can provide a lot of oil or gas, while a less productive one gives less. Factors like the size of the reservoir, the rock’s quality, and the well’s design affect its productivity. To optimize reservoir management, you need a deep understanding of the reservoir’s characteristics and behavior. This includes studying geological formations, fluid properties, and reservoir pressure

Adding to that after some years of production, development of near well-bore skin can hamper well productivity. This can be gauged by conducting Pressure buildup tests for Oil Producers or Pressure fall off tests for Water injectors that can help ascertain presence of skin effect and further well-bore interventions can be carried out to boost production.

Several factors to consider when speaking of production performance and reservoir properties including but not limited to PI, Pr, WC, T, vis and solid production