PETE 4052Well TestingSpring 2002
Lecture 8Fundamentals of Well TestingMarch 15
Fundamentals of Well Testing
Outline
- Synopsis
- What is a Well Test?
- Goals of Well Testing
- Conducting Well Tests
8.0 Synopsis
Reservoir modeling teams can get information about permeability from cores and logs, but these data are often incomplete or may be unrepresentative of properties at reservoir conditions. Similarly, faults may be mapped from well-log data and seismic, but these data are sparse and it is difficult to discern from seismic data (for example) whether or not a fault is sealing. In addition, parameters such as average pressure are very important to reservoir surveillance and management. One of the few ways to get any of these data in situ is by pressure transient analysis. These methods will be the subject of the next several lectures.
Key Concepts
- Definition of a well test
- Goals of a well test
- Things you can’t get from well tests
- Rough process of well testing
8.1 What is a Well Test?
Very generally,
A well test is a period of time during which the rate and/or pressure of a well is recorded to estimate well or reservoir properties, to prove reservoir productivity, or to obtain general reservoir management data.
Several types of “well tests” are described in the following paragraphs:
Flow test
In many situations, especially offshore, more than one well produces through one separator, and often several separators are manifolded into a single “sales” or “export” line which transports produced oil or gas to storage and processing facilities (Fig. 8.1).
This causes a basic problem: although the combined rates of all wells are known (in Fig. 8.1, 3 oil and two gas wells), the rates of individual wells are not known. It is important to know individual rates for material balance and surveillance purposes.
To get individual well rates, most fields have a smaller test separator. This is a separate, smaller treatment system in parallel to the “oil” and “gas” streams shown on Figure 8.1. Wells are periodically switched into the test separator to determine individual well rates. Only one well is flowed to the test separator at a time.
This help allocate the rates, but there are still several problems. The main problem is that the conditions (back pressure and stage pressures – and thus B0) are rarely the same for the production string and the test string. The rates, water cuts, GOR’s, and so on may therefore be different for test versus production separators, for all wells. This is usually accounted for by
allocating production back to individual wells based on the field (or platform) total, and the individual well tests. Of course, this method is only approximate.
Figure 8.1 – Cartoon of a gathering system on a platform, showing why it is difficult to know individual well rates at any time.
There is a great deal of interest in in-line or even bottom-hole flow metering to make this process more accurate (and perhaps to eliminate the need for test separators). However, is difficult to measure multiphase flow rates accurately. The flow testing and allocation process is the standard method for determining well rates in most fields.
Banker’s Test
This is a test which is done to demonstrate productivity, but is not designed such that quantitative estimates of reservoir properties (permeability, area, etc.) can be determined. The sole reason for this test is to demonstrate that adequate rates can be obtained from the well.
RFT
Wells can be tested using wireline-conveyed tools, either in casing or open-hole. These tools (RFT, MDT, etc.) typically are run to the desired depth before actuating levers or other devices to seal them against the side of the wellbore. If the test is incasing, a perforation charge is fired to establish communication between the well and formation. A small volume of formation fluid is then produced (either into the tool or through the tool to the wellbore). A schematic is shown in Figure 8.2 (from the Schlumberger web site, ).
Figure 8.2 – Schematic of a wireline testing tool.
These tests are useful because they can provide a vertical pressure profile, they can obtain pressure samples, and they can provide estimates of formation permeability. However, because the flow geometry is spherical and flow times are short, interpretation can be difficult. In some areas, openhole tools may be too risky to run (lost tools, sticking, etc.).
Drill-Stem Test
In newly developed reservoirs, or in high-risk developments, it may be worthwhile to test the well before completing it or installing full-fledged production facilities. This is usually done with a drilling rig on-site, and the string through which the well is produced is manipulated by the drilling rig. Thus, it is often known as a drill-stem test. An example of a string (from Earlougher) is shown in Figure 8.3.
Figure 8.3 – Downhole equipment for a drillstem test.
Because these tests are expensive, may be risky, and are a lot of trouble to perform, they are only done when they can be justified by the opportunity to obtain badly-needed data.
One problem with conventional drill-stem strings is that the gauges (with electronic memory) are sealed deep in the well, below the packer. There are tools available (e.g., Figure 8.4, again from Schlumberger web site) that allow the pressure measurements to be transmitted to the surface during the well test.
Because it is important to minimize the well testing time, sometimes bottomhole shut-in valves are added to the test string. We will discuss the benefits of bottomhole shutin later in the course; for now, it is enough to know that testing time can be reduced when they are used.
Fluid sampling tools are also added to some test strings, to get fluid samples at near-bottomhole conditions. Such in situ sampling may be very important in near-critical oils or rich condensate reservoirs.
In very environmentally sensitive areas, such as the Chukchi Sea, drill stem tests may be forbidden from producing fluids to the surface. The entire test consists of filling the test string with produced fluid.
Another cousin to the drill stem test is the surge test. If a well is perforated while underbalanced pressure measurements can be used to estimate the flow rate. The flow and pressure data can be used to infer reservoir properties.
Drawdown Test
A drawdown test is one in which the rate is held approximately constant while the well pressure is measured. Ideally, the well pressure should be measured as near to the perforations as possible. The well pressure generally falls over time. The rate at which the pressure changes depends on reservoir and fluid properties, reservoir boundaries, and drive mechanisms. Thus, the pressure response can be used to estimate these parameters.
Production Test
A production test is just like a drawdown test, except that it is generally run for a longer period of time.
Buildup Test
It is hard to maintain a constant rate on a flowing well, but it is easy to keep a well at a rate of zero. We can run a pressure transient test by monitoring the pressure after any sort of rate change; changing the rate to zero has lots of advantages. In a buildup test, we simply shut the well in (usually at the surface, but it may be downhole) and monitor the pressure buildup using pressure gauges.
Interference Test
Sometimes we are concerned about large-scale reservoir property trends. We can monitor the pressure changes at one well (the “observation” well) due to flow rate changes at another well (the “active” well). This can give improved estimates of directional permeability and reservoir storativity.
8.2 Goals of Well Testing
Well tests, if properly designed, can be used to estimate the following parameters
- Flow conductance,
- Skin factor, s
- Non-Darcy coefficient, D (multirate tests)
- Storativity, (interference tests)
- Fractured reservoir parameters and
- Fractured well parameters xf and kfwf
- Drainage area
- Distance to faults
- Drainage shape
On the other hand, we can generally not estimate
- k, h, or individually
- Non-Darcy coefficient
- Distinguish pseudoskins (e.g., partial penetration) from mechanical skin
- The location or properties of (small) heterogeneous regions within the reservoir
- The permeability of altered regions very near the wellbore (a few wellbore radii away)
- Radial variations in saturation and mobility
The goals of well testing will influence the design and conduct of the well test.
Conducting Well Tests
Most well tests consist of changing the rate, and observing the change in pressure caused by this change in rate. To do this, there are four basic requirements for a pressure transient test:
- We need to be able to measure time
- We need to be able to measure rate
- We need to be able to measure pressure
- We need to be able to control rate
Ideally, we would like to control rate at the sandface (that is, at the perforations, or bottomhole) but in most instances we can only control it at the surface. An important exception is when bottomhole shutin devices are used. Bottomhole shutin devices are generally only used on drillstem tests.
Similarly, rate and pressure are best measured at the sandface. This can be accomplished using downhole meters (venturis or spinners for rate, memory or surface-readout gauges for pressure). It is usually difficult to measure rate at sandface, and in practice it is rarely done. It is somewhat easier to measure pressure near the sandface, and because surface pressure data are very difficult to interpret, most well tests use bottomhole gauges. Generally, the gauges are lowered into the well via wireline and are set in a nipple or other landing hardware. For production test or drillstem tests, the gauges may be run in “gauge carriers”, which are just special pieces of tubing with slots for gauges and pressure ports. On critical tests, more than a dozen gauges may be run to ensure adequate data are obtained.
Most gauges are “memory” devices. They store the pressure and temperature versus time using “on board” memory. In old “Amerada” gauges, the memory was a piece of foil that spun beneath a scribing needle attached to the bourdon tube pressure sensing element; modern gauges use electronic (digital) memory. Usually, the engineer does not know the bottomhole pressure history until the gauges are retrieved.
Engineers would like to be able to monitor the pressure buildup at the surface, as the gauges measure pressure downhole. This is possible with some wireline technologies (including the data link, Figure 8.4) or with permanently installed bottomhole gauges, which are becoming more common in high-value wells. However, permanent gauges complicate the wellbore and wellbore assembly, require cable to be strapped to tubing and an extra wellhead penetration, and are relatively expensive (~$250K).
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