Drill Stem Test (DST): Qualitative DST Chart

When drilling has reached total depth and the formation to be evaluated has been determined by samples, logs, and cores, a Drill Stem Test may be ordered.

The testing equipment is attached to the end of the drill string. A hydraulic valve system keeps the string dry as it is being lowered into the wellbore. The testing equipment also incorporates a sealing device or packer that effects against the wellbore.

When testing equipment has reached the prospective formation, the formation is isolated from the rest of the wellbore by the packers. A valve opens and the formation is allowed to produce into the dry drill pipe.

At this time, a graphic pressure versus time chart of flow performance is recorded. This chart is produced by mechanical recorders and/or electronic pressure/temperature gauges. The data derived from the Drill Stem Test (DST) give a computation of the formation’s permeability, damage ratio, productivity index, transmissibility and radius of investigation.

After the operator determines that a formation test is to be conducted, the test tool is assembled and lowered into the wellbore. A graphic chart is obtained from two recorders.

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ESP design – Step 2: Production Capacity

Once the first step “Collect basic data” is performed, we pass to the ” step 2: Production Capacity “ of the ESP Nine Step Design Procedure. It consists on predicting the well inflow performance which represents the relationship between pressure and flow rate at the well face of an individual well and it is physically defined as the well flowing bottom-hole pressure (Pwf) as a function of production rate. It describes the flow in the reservoir.

Many inflow performance relationships (IPR’s) are described in the literature. In this article, we will briefly present three of the most widely used IPR’s to describe the well performance:


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Vogel’s inflow performance relationship

In 1968, Vogel established an empirical relationship ( Vogel’s inflow performance relationship )for flowrate prediction of a solution gas-drive reservoir in terms of the wellbore pressure based on reservoir simulation results.

Vogel’s Model compared to PI Model…

The PI model works very well for single phase fluid (water, oil, or water/oil) flowing into a wellbore, even though water and oil are two separate phases, they are considered as a single phase since they are both liquid.

But what happens when gas comes out of solution?

” The flow velocity of a fluid in a porous medium is inversely proportional to the fluid viscosity. Typically, gas viscosity in the reservoir is about fifty times smaller than for liquid oil and consequently, the gas flow velocity is much greater. As a result, it is normal, when producing from a reservoir in which there is a free gas saturation, that gas will be produced in disproportionate amounts in comparison to the oil “. (Dake, fundamentals of reservoir engineering).

Compared to liquid, gas has much higher permeability and much lower viscosity. These two factors will give the gas a much higher flow rate than liquid inside the reservoir, so that:

QG >> QL

Below the bubble point pressure, the solution gas escapes from the oil and become free gas. The free gas occupies some portion of pore space and reduces flow of oil. This effect is quantified by:

  • A decrease of oil Relative permeability
  • An increase of oil viscosity (as its solution gas content drops)

Therefore, the combination of the relative permeability effect and the viscosity effect results in lower oil production rate at a given bottom-hole pressure.

Graphically, it would looks like this:

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Well Inflow Performance

Well Inflow Performance represents the relationship between pressure and flow rate at the well face of an individual well. The scientist Darcy was the first studied extensively the relationship between pressure and flow rate. His experimental studies consist on creating a pressure differential across a porous media and measured the resulting flow rate.

Darcy’s experiments result in what is known as “Darcy’s law”. For general flow through a porous media:

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