Well Testing is the process of capturing data from a live well over time to analyze and understand the well behaviour in real-time. A well test acquires data on the hydrocarbons properties, reservoir temperature and pressure, drainage area and shape, and water-to-oil and gas-to-oil ratios. In order to acquire the most accurate data, different production rates are tested in order to observe any changes in behaviour. Testing a well is one of the key tools in effective field evaluation and further development and can help ensure that the facility design is fit-for-purpose for the field.
Well testing (surface in particular) is one of the most hazardous and risky activities in the oil and gas industry. Detailed planning and expertise in various areas is required to ensure safe well-testing operation.
Well testing is conducted at various stages of E&P projects, with different objectives at each stage. Information obtained through well testing is used in conjunction with other data, such as seismic, logging, mud logs and core analysis.
As aforementioned, well testing is mainly used during exploration and appraisal activities, development and to a lesser extent during production. During exploration and appraisal the following activities are carried out:
Exploration and Appraisal stage
- Sampling of fluids
- Measuring pressure in the reservoir
- Estimating volume and oil-in-place
- Permeability (the ability of liquids to flow through the rock)
- Identifying information on shape, size and geological complexity of the reservoir
Well testing is broadly divided into the following categories:
Drill Stem Test (DST) is a process that tests pressure, permeability and the production potential of a productive zone, while the drill string (i.e. drill pipe and other assemblies) is in the well, by temporarily completing the well. A special packer type tool is used to isolate a section of the well during the well test. Also, a shut-in tool is lowered into the well, which provides full control and allows the opening and closing of the well. Pressure and temperature gauges are installed on a DST assembly. Primarily used in an open-well environment and during exploration, during the DST test, fluids are produced through a hollow in the drill pipe all the way up to the surface, where special equipment is mobilized for well-testing operations (aka a Surface Well Test). Sometimes, companies may test down-hole only and produce only the volume of liquids that the hollow structure and volume of the drill string can accommodate. In most cases, this is done for environmental and safety reasons and is called a closed-chamber test or a non-flowing to the surface test.
Generally, a DST test is conducted in stages, i.e. a flow period between 5 minutes and 2 hours, then a period of time to build up the flow in order to understand the pressure behavior, followed by a longer flow period (up to 3 days) to pick up the trends in the flow and its stability. Once the DST test is completed, the fluid sample, data on the pressure behaviour and hydrodynamics, the formation properties and the flow rates are available for further analysis. DST tests can be classed as: 1) flowing to the surface and 2) closed-chamber tests (non-flowing). Sometimes, a longer test, called an Extended Well Test, is conducted to better understand the field.
Key benefits are:
- Measure average and static reservoir pressure
- Allows calculation of well productivity
- Identifies reservoir boundary and drainage radius
- Identifying information on the shape, size and geological complexity of the reservoir
- More accurate reliable in reserves definition
Flowback Testing (Surface Test) is when a well is under real production and oil is flown through a system of separation and measuring equipment (i.e. a well-testing package), to determine the commercial potential of the well and reservoir. A well-testing package generally consists of the following equipment:
- 3-phase separator to phase out water, oil and gas
- Sand separators
- Choke system to reduce and manage pressure
- Heaters and heat exchangers
- Tanks and pumps
- Flare boom to burn-off produced gas
- Safety and emergency equipment
- Down-hole equipment, as required
- Control unit in the surface
Closed-chamber Test (Down-hole Test) is when a well is under real production and oil is flown to the chamber inside the DST assembly, without going to the surface, i.e. the surface valves are closed. Sometimes, low-pressure nitrogen is injected into the DST assembly. Once the flow of fluids starts, nitrogen (or air) is compressed inside the chamber and the liquid volumes can be calculated. This technique is used more widely than the flow test, due to its lower costs and lower HSE risks.
Formation Test, Repeat Formation Test (RFT), Reservoir Characterization Instrument™ (RCI™) and Modular Formation Dynamics Tester™ (MDT™) all are formation tester and sampling tools that measure the formation pressure vs depth at various points in the open hole using a wire-line, as well as collecting fluid samples. Once the tool is run into the well on a wire-line and sealed against the wellbore by opening the valve, fluids are flown into the sample chamber. During the flow, reservoir pressure data is recorded, which allows calculating the permeability (the ability of the liquids to flow through the rock) of the formation. Liquids that are inside the tool are brought to the surface for further analysis for assessing their chemical and physical properties. RCI/MDT are more advanced options of RFT, providing more accurate data and less contaminated samples. In tandem with other tools, a number of more detailed and real-time data collection and analysis methods can be conducted. One of the key drivers to use this test is that there is an indication that the reservoir could be compartmentalized, and to understand if a full DST test is required.
Key benefits are:
- Measures initial reservoir pressure
- Identifies the type of fluids inside the rock
- Determines fluids contact
- Collects samples at the reservoir conditions
- Records and measures any vertical communication between the layers
- Allows real-time fluid analysis
Generally, the DST test takes more time than MDT, e.g. 30 days vs 5 days, or 7 days vs 2 days. In order to book resource estimates and to support investment decisions, DST data is a must, but RCI/MDTRCI is the first step. The decision on which test to use is driven by the test objectives, the well type and environment, costs and the regulatory requirements. Below outlined a comparison summary of two methods.
Production Test is very similar to DST, but instead of the drill string, existing production string (tubing) is used. This test is used after the well has been completed and put into production. It is mostly used during the production phase and to a lesser extent during development (if an extended well test was chosen). The production test provides a detailed insight into fluids and pressure behavior over time and recommendations if any well intervention is required. One of the first indicators of the production test requirement is decreasing pressure or increased gas-to-oil ratio.
Fluid Sampling and Analysis. This is the process and set of techniques to acquire and analyze reservoir fluids. High-quality samples are required to determine the number of parameters for the design of future production facilities and recovery strategies. Information obtained from analyzing the reservoir fluids is used by:
- Flow assurance engineers, to ensure the flow, corrosion remediation strategies and to address pipeline issues.
- Facility designers, for material and concept selection.
- Completion and Production engineers, for completion design and for material selection for future well intervention options.
- Geologists and Geophysicists, for various correlation and geotechnical studies.
- Reservoir engineers, to estimate recovery and to run simulations.
Samples of fluid are collected using DST or RFT/MDT/RCI test methods. Once collected, the samples are analyzed in a laboratory to provide information on:
- PVT: Pressure-Volume-Temperature
- Gas-to-oil ratio
- Physical properties and chemical composition
- Flow assurance
- EOR (Enhanced Oil Recovery) strategy analysis
Nowadays, onsite fluid analysis is becoming more sophisticated and efficient, eliminating the need to send samples to a laboratory. There are two ways to obtain fluid samples: down-hole and surface. Each has its own advantages and disadvantages and application; for example, surface sampling provides full control of the operation and does not impose any restrictions on the volumes and size of the sample, while down-hole sampling provides representative samples of fluids at the exact spot(s) in the productive zone.
The cost of conducting well testing is very significant and, depending on the well test requirements, may be in excess of US$15MM per well or as much as 30% of an exploration well costs. An effective well-testing strategy and accurate sampling and analysis are highly critical for a project's success.