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.
Risks & Opportunities
Risks & Opportunities
- Flaring gas in high H2S wells is a big challenge. The residual H2S will dissolve in the air and will eventually fall down to the earth. Depending on the wind direction, this highly toxic H2S residual may fall to populated areas or a platform/rig, when done offshore
- Multiphase flow meters may reduce a need for flow tests and test separators, reducing production loss during testing and HSE safety risks
- It is generally accepted by the industry that there is a risk of a formation test sample contamination when oil-based mud is used for drilling operations
- Formation testing equipment must be run by highly experienced engineers and wire-line operators
- Detailed analysis of the value of obtained information vs. cost to obtain that information is important
- Designing and planning a well test programme is critical
- Always look for testing equipment (could be mobile) that is the right size and spec for the requirement
- Tubing conveyed sampling allows utilization of sampling tools to be used with a DST string, hence reducing the risk and rig time, as well as improving the qualify of samples
- In-situ fluids testing and PVT analyses might provide the most accurate data
- Well-testing-while-drilling is another technology that gains traction in the market and reduces HSE risks and costs of well testing operations
- Utilization of well testing vessels in offshore projects may provide the following benefits:
- Captures gas that is normally flared
- Reduces HSE risks
- Allows higher flow rates when compared to the drilling rig, which in turn allows longer well tests, if required
- Option to use commission an extended well test ( EWT) and early production systems, used in tandem with a tanker. This provides better project economics and a better understanding of reservoir behavior.
Supply & Demand Dynamics
Supply & Demand Dynamics
Demand for well-testing services is driven by exploration and appraisal activities, as well as by field development and redevelopment, and to a lesser extent by well intervention. Around 60% of well-testing services are carried out during exploration and appraisal activities, with c. 25% done during development or reappraisal phases and c. 15% during the production stage. Well testing has been traditionally only a small market in terms of the volume of jobs, but it is traditionally significantly high in revenue. The North American market is the highest segment (almost 45%), followed by the Asia Pacific and Europe. These three geographic areas represent more than 75% of the global market, with the Middle East constitutes less than 5%.
Between 2020 and 2023 exploration activities in the Middle East are expected to grow, largely in the UAE. Otherwise, brownfield projects dominating the investments are expected to result in a moderate growth of production testing.
As a result of the current industry downturn, the demand for well testing services dropped significantly. The demand is not expected to stabilize till Q1-Q2 2021.
The supply of well-testing services comprises personnel and equipment. Due to the complexity and risks of well testing, a great deal of planning is required, whereby engineers from various domains work together to design a well testing programme. This planning period can take up to 6 months. As a result, this category is very manpower intensive and requires experienced and highly qualified engineers. In many occasions, companies outsource part of the well-testing planning to a specialized consultancy.
The equipment used comprises flow lines, chokes, separators and more sophisticated burners, flow meters, chokes, tanks, and proprietary down-hole tools. Pressure rating plays a role and hugely affects the available supply of well-testing equipment. Except for proprietary formation testing tools, most of the well-testing equipment is manufactured by companies that do not provide well-testing services directly. In addition, around 50% of a standard surface testing equipment package is sourced on a rental basis from 2nd or 3rd tier suppliers.
Main manufacturing facilities of well-testing equipment are concentrated in key hubs in North America, the North Sea and South East Asia. Due to high-risk operation, the integrity, reliability and pressure capabilities of well-testing equipment requires a significant QA/QC process, equal to those in pressure vessels, wellhead and X-mas tree manufacturing.
Lead times of a well-testing package vary depending on the pressure rating requirements. A full, high pressure (15k) DST kit will not be available immediately and may require a lead time of up to 3-4 months.
Key services companies that have historically dominated the well-testing segment are Schlumberger, Expro Group, Baker Hughes and Halliburton, with many more providers in a lower-tier market, where temperature and pressure regimes are less severe and down-hole tools are widely available in the marketplace.
Well testing market could be divided into a segment consisting of two tiers: 1) lower-tier, whereby equipment used, is very common and designed for lower pressure and temperature applications and 2) higher-tier segment is more critical and exhibits higher HSE risks. Other down-hole conditions such as H2S and CO2, affect the complexity as well. While the lower-tier market is highly competitive, with a large number of players of various sizes, the higher-end is very compact. Yet, it is open enough to ensure that services are obtained in a competitive environment.
Track record and experience of service companies, that is essential for buyers, in higher-tier markets, in particular, make it hard to enter for new service providers. In addition, due to the high fixed cost structure of this category, revenue generation is important to service companies. This may result in lower / flexible margins in the lower-tier market, thus making it more competitive.
In certain applications, down-hole equipment is proprietary to a service company and is not available to a wider supplier base. Those tools are part of the competitive advantage of the top service companies.
Cost & Price Analysis
Cost & Price Analysis
As a result of increased exploration activities over the last several years, prices for well testing services have been showing an upward trend on a global basis. This segment is highly cyclical on the demand side, as such service providers tend to keep the capacity balanced, and in times of higher demand, prices are going up. In addition, due to the call-out nature, the fixed costs are high. Coupled with cyclical demand, and balanced capacity, opportunistic pricing strategies by suppliers is very common in this category.
What is also present in this segment is price skimming, i.e. a service company will charge a premium for a higher technology tool that produces significant benefits for operators. Due to high R&D and G&A costs, integrated companies tend to price their services higher than smaller or niche service providers. Historically, this category was dominated by bigger and integrated service providers.
Prices are expected to continue sliding down in 2nd half of 2020 due to oversupply. Yet, this may be affected by contractors writing off their old and non-competitive assets
Due to the nature of the services, where it is based on call-out, the well-testing market is known to be a high-fixed-cost category, whereby equipment is purchased and stacked till there is a requirement in the market.
Majority of the components in well-testing equipment are made of steel (carbon and low allow steel) and require highly specialized manufacturing practices and processes. In addition, in certain applications, down-hole equipment, which is proprietary to certain companies, requires precise engineering and manufacturing.
Key cost drivers are:
- Steel prices. Directly impact the cost basis
- Personnel costs. In complex and environmentally sensitive applications highly qualified engineers are key. In parallel to that, this is a very manpower-intensive category and requires experienced and highly qualified engineers. Historically, well testing engineers have been one of the highest-paid in the oil & gas industry.
- Manufacturing costs. This can take the biggest share, as the processes involved in well testing equipment manufacturing are very long and costly. Manufacturing processes include heat treatment, cladding, casting, special welding, threading, and inspection. In order to accommodate such a variety of processes, manufacturers incur huge fixed costs to maintain and operate such facilities. Manufacturing costs are significantly less in well-testing equipment that is used in less severe environments, due to lower technical features required. Down-hole tools are considered to be a very high precision and high qualify manufacturing, which require a significant amount of highly qualified & trained personnel.
- Pricing strategy. Manufacturers or owners of well testing equipment tend to provide better pricing to those service companies, who provide bigger revenue for them. Hence, smaller and niche service companies would incur a higher acquisition cost that will be reflected in their prices.
- Research & development costs. Manufacturers and service providers ( in particular) spend a significant amount of capital on R&D to be competitive and meet the challenges. Time to market becomes very critical for manufactures and pay-back period of R&D costs is usually heavily accelerated at the early product stages, i.e. when introduced and during the growth stage.
- Maintenance costs. The reliability and integrity of well-testing equipment, both surface and down-hole, is of utmost importance and represent a very high HSE risk. Hence maintenance plays a key role. Following manufacturer QA/QC processes, inspection and pressure testing requirements is a must. Electronics installed on the down-hole tools operating in a high-temperature environment is prone to failures.
Total Cost of Ownership
Total Cost of Ownership
Below are the important areas to look at for total cost of ownership
- Rig-up / rig-down time makes a significant difference when evaluating options. In the offshore environment, this is particularly evident when high a rig/vessel day rates are incurred.
- Sampling time and/or equipment working in tandem, whereby no extra down-hole trips required, all contributing to the total cost, in particular when high rig/vessel day rates are incurred.
- The number of DST tests conducted within consecutive years is an important indicator when looking at service companies' track records.
- Pressure and temperature rating and the size of equipment, all have a significant impact on well-testing costs. Hence the right-size approach is important. Mobile testing equipment that is the right size and spec for the requirement, provide significant cost efficiencies.
- Developing long term relationships with service providers is very important, in particular in the higher-tier segment.
- Adapting effective segmentation methodologies to carve out services into the lower-tier market, in order to enhance competition, while still having access to the expertise of worldwide know-how, might bring significant results.
- In multiple field operations, purchase vs. rent might be an attractive option for a lower-tier market and/or production testing segment.