WELL TESTING

What is a Well Test?

A Well Test is a flow experiment carried out in a reservoir. Normally fluids are produced from a well, although sometimes water can be injected, at measured rates. The flow of these fluids induces a pressure transient that probes a region of the reservoir proportional to the duration of the test. The pressure transient induced during the flow period continues to travel into the reservoir even after the well is shut in. Once the flow ends, a second pressure transient is induced that also probes the reservoir. The concept of deconvolution benefits from this feature. The pressure transient is affected by multiple reservoir attributes as well as by properties of the fluid present within the pore space.

Customarily, when producing hydrocarbons during a well test, the hydrocarbons are flared. In many environmentally friendly countries, this practice is no longer allowed. Produced fluids must be stored and transported to a production facility. This presents a problem in offshore and remote locations. But engineering ingenuity is helping to overcome this inconvenience.

The measured production or injection rates and the recorded pressure, usually monitored with downhole gauges, are then analyzed to obtain information from the reservoir, the wellbore completion, and the quality of hydrocarbons present in the reservoir. The gauges used to record pressure also record temperature. Traditionally, temperature has not been used in analyzing a well test, even though the downhole temperature also provides information on the reservoir. Recently, there has been an effort to incorporate downhole temperature into the interpretation of well tests. See, for example, SPE-163437, SPE-163727, SPE-166120, and SPE-168995. To the best of my knowledge, this is not an approach that has received widespread use yet.

Why test a well?

A well test provides information not available from static measurements. A test is carried out to gather information to mitigate risks in:

Geology

Enhancing confidence in geologic interpretation as well as reserves estimates

Engineering

It is a direct measure of the actual and potential productivity of a well
Incorporates proven methods to capture reservoir-representative, uncontaminated fluid samples for PVT and Flow Assurance analyses
Identification of potential production problems such as sand production, fines migration, presence of asphaltenes or paraffin, and possibility of water/gas coning

When to test a well?

A well can be tested during the entire life cycle of a field. The reasons for carrying out a well test differ, depending on whether it is an exploration, early appraisal to development, or production well. Without attempting to define fixed brackets, one can state the following

Exploration: A test is normally carried out to estimate a minimum connected reservoir volume, reservoir deliverability, as well as reservoir and fluid properties.

Appraisal to Early Field Development: In this instance, the emphasis is on reservoir description.

Production: In the late stage of a field, the emphasis shifts to reservoir management.

Well Test Objectives

Given the complexity of a well test, it is imperative to follow a methodical approach. If followed, a logical progression leads to the successful completion of a well test. Objectives must be clearly and completely defined. All stakeholders must agree on those objectives before any design work and equipment allocation begins. Any subsequent proposal to modify the agreed-upon objectives must be documented and circulated to each stakeholder.

It is essential for one person to be responsible for designing the test, surface and downhole equipment requirements, test procedures, data collection, data quality control, interpretation of test, and presentation of results. Every single step must be properly documented. This is of value during execution as well as for future reference. When several people perform these functions, a loss of focus often ensues that may threaten the success of the test.

Typical objectives for a well test are to:

Conduct a safe test
Confirm the existence of hydrocarbons in the reservoir
Determine the flow rate under typical operating conditions
Obtain uncontaminated fluid samples for PVT and Flow Assurance analyses
Measure reservoir temperature and pressure
Estimate the flow capacity (kh) of the producing interval
Determine the level of damage or stimulation near the wellbore
Identify reservoir heterogeneities within the volume surveyed by the test
Calculate absolute open-flow (AOF) potential
Ascertain hydraulic-fracture properties
Establish a minimum-connected volume
Determine properties of a horizontal well
Corroborate inter-well connectivity
Evaluate properties of multi-later reservoirs (A multi-layer test should involve running a production-logging tool (PLT) string to determine flow contributions from each layer.)
Verify injectivity capability

Before conducting the test, once the equipment has been procured and a rate schedule has been designed, it is strongly recommended to have a Well Test On Paper (WTOP) exercise with all the parties that will be involved during the execution of the test. During the WTOP exercise, each possible source of problems at every step should be presented. Contingencies to reduce or eliminate each problem must be discussed and preparations must be set up to minimize those hazards. A Risk Assessment document can thus be prepared or supplemented.

Issues to Consider

So, a decision has been made that a well test is required. Before starting the design process, it is crucial to consider the following issues:

What type of test is required – Oil, Gas, Injection, High-Pressure & High-Temperature (HPHT), Extended Well Test, Interference, Pulse Test, Multi-rate, Closed Chamber
Lead time – Because in remote locations or in sour reservoirs specialized equipment may be required, it is important to consider the logistics, planning, manufacturing of equipment, and transportation to location. Under some circumstances, a 2-year lead time may be necessary
Cost – rig rates, time-value of information, duration of test
Environment – zero emissions, contingency for spills
Technology – HPHT, equipment, environment, surface readout, equipment redundancy
Partners – managing expectations, government regulations
Location – remote location, arctic environment, offshore, deepwater, accessibility
Reservoir – structure, stratigraphy, heterogeneity
Fluid – volatile, non-hydrocarbon [sour (H2S) or inert components(CO2)], possibility of hydrate formation, low API oil
Equipment – downhole and surface, and possibly a PLT string for multi-layer tests