Drill stem test

Before we get into the pressure transient analysis, let us understand some basics of drill stem testing.

Drill stem testing is an oil and gas exploration procedure to isolate, stimulate and flow a downhole formation to determine the fluids present and the rate at which they can be produced.

A basic drill stem test BHA consists of a packer or packers, which act as an expanding plug to isolate sections of the well for the testing process. Then there are valves that can be operated from the surface, and recorders used for documenting pressure during the test (Image 1).

Image 1: Drill steam test

The drill stem test in Well 15/9-19 SR

Objective

• Quantify amounts of sour gas in the well stream at the surface and down hole
• Obtain initial formation pressure
• Collect data for the evaluation of reservoir properties and productivity
• Obtain formation fluid samples and separator fluid samples
• Investigate reservoir boundary effects

Test Performance:

The rate history includes the initial clean-up, followed by the test and the main flow. The well was perforated in underbalance (>80 bar), using diesel as a cushion and with an open choke.

The rate was gradually increased to a maximum of 1358 Sm³ /d for which two test separators were used.

The well was opened at a rate of 75 Sm³/d for PVT sampling after the initial build-up. Once the sampling was done, the well was opened for the main flow period at a rate of 1290 Sm³/d. It was then shut off for the main build-up (Image 2).

Image 2: The performance of bottom hole pressure and temperature for the whole test period

The reservoir pressure can be extrapolated to 327.7 bar.

The pressure response indicates several boundary effects. Barriers are identified approximately 60 m and 250 m from the well. (Image 3)

Image 3: The pressure data with Type Curve match

Furthermore, an increase in flow capacity is observed approximately 125 m from the well.

Flow capacity is the product of permeability and reservoir interval thickness

Permeability is calculated using the data from the main pressure build-up period. The test analysis gives a permeability value of ~900 mD. The average core permeability varies between 310 mD and 2.9 D. Based on the core observations and log data, permeability distribution is expected to be non-homogeneous, hence the well test permeability is believed to correspond with average of the core and log data.

The productivity index (PI) is calculated to be 145 S m³ /d/bar. This is done using flow rates from the first and the second main flow.

Total skin from the test analysis is approximately -0.2 and the completion skin is 0. By taking into account the well deviation (in the perforated interval), of 50.2 degrees, a damage skin of 1.7 can be computed.

Total skin also known as effective or apparent skin is a summation of the following skin components:

Skin (or pseudo-skin) due to inclination (s_inc) : In a well that does not penetrate a formation vertical to the bedding plane, the communication or contact area with the formation increases.  This reduces the pressure drop required to obtain a flow rate equal to that of a well that penetrates a formation vertically.  Therefore, the flow efficiency is improved, which causes a reduction in the apparent or total skin factor (s’).

Perforation with high under-balance is supposed to stimulate the near-wellbore effect, causing a reduction in skin factor. The under-balance is achieved by using diesel as a well fluid during perforation.

However, experience with the Statfjord Field shows that higher rates give positive skin as a result of pressure loss through the drill stem equipment between the perforated interval and pressure gauges.

A skin of 1.7 is the equivalent of a pressure loss of 1.8 bar. This is within the expectations of a hydraulic friction loss between the perforated interval and the pressure gauges (197 m MD); Given a heavy and high viscosity oil, and a flow-rate of 1310 S m³ /d.