Well Test Introduction

Well Test Introduction

Well testing assesses a well’s production capability and reveals reservoir properties under dynamic conditions—while fluids are flowing. Unlike static measurements such as wireline logging, a well test shows how the reservoir behaves during production and can help inform long-term development and management decisions.

Historical Development

• Fossil fuels became increasingly important as industrialization increased demand for energy.
• The first commercial oil well was drilled near Oil Creek, Pennsylvania, in 1859 by Colonel Edwin L. Drake.
• Well testing began in the early 1920s, with basic pressure measurements recorded using a Bourdon-tube and stylus arrangement.
• Analysis methods advanced in the 1930s and 1950s. Electronic recording equipment in the early 1970s and computerized systems in the early 1980s further improved data collection and interpretation.

Main Purposes of Well Testing

Tests are designed to answer questions about:

• Produced fluids: Whether the well produces oil, gas, water, or solids.
• Well productivity and reservoir deliverability: How much the well and reservoir can produce, and how that capacity may change.
• Reservoir size and characteristics: The reservoir’s potential, flow capacity, boundaries, fractures, and heterogeneity.
• Formation damage: Whether restrictions near the wellbore are reducing flow, and whether treatments such as acidizing or other stimulation may be appropriate.

Types of Well Tests

• Productivity tests assess the well’s ability to produce fluids. They can identify produced fluids and estimate reservoir deliverability.
• Descriptive reservoir tests investigate reservoir characteristics in greater detail, including fractures, boundaries, and variations in reservoir properties.

When Tests Are Performed

Testing may take place at different stages of a well’s life:

• During drilling: To assess whether the formation contains viable hydrocarbons and whether the well has production potential.
• During completion: To confirm reservoir properties and help select suitable completion methods.
• During production: To monitor flow behavior and reservoir performance, and to inform long-term operating and development decisions.

The purpose of each test should be defined in advance so the test program collects data relevant to the decisions being made.

Typical Well-Testing Operations and Sequence

1. Define the test objectives. Specify the reservoir or well questions the test is intended to answer, then design the test program accordingly.
2. Open the target interval. Tubing-conveyed perforating (TCP) creates openings in the casing at selected intervals, allowing reservoir fluids to enter the wellbore.
3. Convey and control the flow. During a drill stem test (DST):
   • A packer isolates the target zone.
   • A tester valve controls whether the well is opened or shut in.
   • Tubing or pipes provide a route for fluids to reach the surface.
   • A subsurface safety valve can stop flow in an emergency.
4. Manage flow at the surface.
   • A flow head directs produced fluids into the surface test system.
   • A choke manifold regulates flow rate and pressure.
   • A separator separates produced fluids into oil, gas, and water.
   • Burners safely flare unwanted or excess gas.
5. Flow the well and collect data. The well is typically flowed at a controlled rate for hours or days, depending on the test objectives.
6. Shut in the well. After the flowing period, the well is closed and pressure-buildup data is collected.
7. Analyze the results and handle test fluids. The data is used to evaluate well productivity and reservoir behavior. Produced test fluids are disposed of after operations.

Key Measurements and Analysis

A well test commonly records:

• Flow rates for oil, gas, water, and any solids.
• Pressure and temperature at the surface and downhole.
• Representative fluid samples from the surface and bottomhole for pressure–volume–temperature (PVT) analysis.

These measurements help characterize the fluids and evaluate how the well and reservoir respond to production.

Well-test interpretation may include:

• Productivity index (PI): A measure of a well’s ability to produce fluids.
• Inflow performance relationship (IPR): A relationship between flow rate and pressure, used for oil wells.
• Gas deliverability curves and absolute open flow (AOF): Tools for assessing gas-well capacity under different pressures and estimating maximum flow potential.
• Static reservoir pressure and formation flow capacity (KH): Indicators of reservoir energy and the ability of fluids to move through the formation.
• Skin factor (S): An indicator of near-wellbore damage or flow restriction. A high skin factor may prompt consideration of stimulation or another treatment.

Test results can influence field-development planning, so measurements and interpretation should be tied to clear objectives.

Speakers and Sources Featured

• Speaker: One instructional narrator; no separate interview speakers are identifiable in the subtitles.
• Historical people or sources mentioned: Colonel Edwin L. Drake; Muscat (name as transcribed); Miller, Dyes, and Hutchinson (names as transcribed).