Acoustic Well Sounders

Subtopics:

Acoustic well sounders (AWS), or echometers, can be a very effective way of obtaining subsurface pressures. Their major advantages are:

Simplicity
Cost effectiveness – not having to pull pumps and rods in order to land subsurface recorders
Less disturbance to the formation – not having to kill the well, or damage the formation with kill fluid

Because of these significant advantages, AWS measurements are widely used throughout the oil industry as a means of obtaining subsurface pressures.

Quality

The best way to obtain a subsurface pressure is to measure it directly at the sandface. Subsurface pressure gauges usually yield acceptable results, except in the case of a total failure of the gauge. By contrast, you can use AWS as an indirect way of determining the pressure at the subsurface, and the quality of the results can be quite variable. In many cases, the results are quite acceptable (within the objectives of the test). However, in many other cases, the results from AWS are grossly in error for a number of reasons.

In other words, unless special precautions are taken, it is very easy to obtain the wrong answer with AWS.

Fekete’s experience and expertise in AWS surveys is summarized in this abstract. It provides an outline of procedures to assist you in your AWS sandface pressure surveys and calculations, and considers both practical and theoretical requirements for a successful survey.

Planning & Preparation

Thorough planning of the AWS pressure survey must be implemented prior to the survey to ensure that there is success in production optimization and reservoir management.

One of the best ways of achieving this goal is to have a survey coordinator who is responsible for planning, scheduling, and coordinating personnel and equipment needed to conduct the field work and analysis of acquired data. The survey coordinator must have a thorough understanding of the field procedures involved with conducting an AWS survey, as well as test interpretation skills to ensure that sufficient quality data is acquired for the well to be returned to production at the earliest possible time.

In wells where wax problems occur, a hot oil (or treated water) program should be performed long enough in advance to allow the well to return to normal pumping conditions prior to the survey. Also at this time, the wellhead should be inspected for any leaks, and casing valves serviced.

One day prior to conducting a foam depression test, flow rate measurements should be conducted and compared to historical data. Experience suggests that two measurements, of 12 hours each, be conducted to verify measurements. Reid measuring devices should be recently calibrated to ensure accuracy.

The most recent and complete tubing tally and wellbore configuration should be obtained from the well files. Remember, the collars of the tubing are what we are counting. The degree of error here is reflected in the accuracy of the sandface pressure, even when employing the Acoustic Velocity method, which must be calibrated using the count of the collars.

In order to determine proper parameters for the analysis of the data, the most recent Pressure, Volume, Temperature (PVT), petrophysics, and geology data should be acquired for the pool.

Sampling and analysis of the oil, water, and gas should be conducted by qualified personnel only.

Where possible, sampling should be conducted from a separator, noting the temperature and pressure at which the sampling was conducted.
Otherwise, stock tank oil samples, casing gas samples, and representative water samples should be obtained and analyzed.
All sampling should be done in duplicate and compared to ensure quality.
All inconsistencies should be resolved prior to the pressure data being analyzed.

Required personnel should be notified well in advance of the survey. If a field survey is being conducted, ensure enough personnel are available to conduct the survey to its completion. Don’t forget support staff (i.e., field operators, chart readers, etc.). Remember, pressure surveys may require 24-hour, 7 days a week monitoring to return survey wells to production as soon as possible.

Field Supervision

Supervision of the data gathering in the field is extremely important. As the saying goes "garbage in - garbage out". Incorrect field-data-gathering techniques result in inaccuracies of the final pressure calculations.

Only experienced personnel (from within or contracted) should be responsible for acquiring field data. Field measurements should be taken with properly calibrated instruments. Casing pressures are measured using either a deadweight or a digital pressure transducer. Fluid levels are recorded using a dual-channel recorder. If a single-channel recorder is used, two shots are required: 1) collars, 2) fluid level to verify liquid level.
Strip-chart interpretation should be performed at least twice to verify results. Consecutive strip charts should be interpreted by juxtaposition. This is done by laying each strip chart side-by-side in the order of shots. By doing this, you get a true picture of the fluid movement throughout the shut-in.
In conducting either a one-well survey or a total field survey, a test coordinator is required to ensure proper procedures are followed, quality data is acquired, and proper analysis of the data is received (in order to achieve the test objective and return the well to production at the earliest possible time). Remember, one of the benefits of AWS surveys is that the progress of the test can be monitored daily from field readings.

Wellbore Dynamics

To better understand and quantify the results of an AWS survey, experience has shown that wellbore dynamics must be considered during a pressure buildup monitored by AWS.

1. Determination of sandface Pressure After Shut-In

Theoretically, the calculation of the shut-in sandface pressure (pws) is quite easy.

Where

pcs is the shut-in casing pressure measured by either a deadweight, or a digital pressure transducer. A normal pressure gauge is not recommended due to normal "wear and tear" of field operations.

Note:

Prior to commencing and throughout the survey, ensure that there are no leaks at the wellhead by inspecting it visually and listening for small leaks.

DpGas is the pressure exerted by the gas column in the annulus. This is easily calculated using the Cullender and Smith method with very acceptable accuracy.

DpLIQUID is the pressure exerted by the liquid column in the annulus. This is where the difficulty comes and consideration of wellbore dynamics is essential.

2. Determination of Liquid Level

As previously discussed, there are a number of methods for determining liquid levels.

Dual Channel – These machines produce a strip chart indicating tubing collars on the bottom and liquid level on the top. This provides easy verification of the liquid level at a glance.
Single Channel – The single channel fluid level machine has the capability of providing tubing collar, or fluid level strip charts individually. In order to compare both charts, they must be placed side-by-side and verified.
Acoustic Velocity – This method of determining fluid levels is based on the velocity of sound in the gas, and the time it takes for the sound wave to be reflected off the gas-liquid interface. Acoustic velocities are sensitive to gas composition, temperature and pressure, and thus, may vary during the test.

All of these methods may be affected by the presence of a "foam" column, as the acoustic reflection indicates the top of the "foam" column rather than the top of the "liquid" column.

3. Foam Depression Test

The foam depression test is used to minimize the effects of the "foam" column. It is performed on a pumping oil well to determine the fluid level in the annulus and the flowing pressure prior to shutting the well in. It consists of first "shooting" the annulus during normal pumping conditions, with the casing valve open, then shutting the casing in and "shooting" the annulus at specified time intervals while the well continues to pump. The adage of "move it to prove it" means that while the casing is shut-in and the fluid level is being monitored, a "gradient" of the fluid can be detected. This procedure is carried out until the "foam" gradient is diminished and a "liquid" gradient is observed.

After a "liquid" gradient is established, a reasonable estimate of pwf can be calculated. In some procedures, correlations are sometimes used to estimate pwf.
The lower the liquid level is, the smaller is the error in the calculated pwf. However, care should be taken not to depress the fluid lower than one joint above the pump, so as not to have gas bypass occur in the pump.

A foam depression test can vary in time to complete; therefore a review of past tests assists you in planning your AWS survey. The foam depression test is usually performed immediately preceding the buildup test.

4. Determination of Liquid Gradients

The liquids in the wellbore consist of oil, water, or a combination of both. The pressure exerted by the liquids is the sum of the water and oil columns. Under normal conditions, the water gradient is known and the oil gradient is determined from correlations (i.e.,AEUB Guide G-5). However, these correlations have limitations. Once exceeded, other alternatives are required such as:

PVT. Correlations
Equation of State Calculations
Static Gradients

5. Determination of Oil/Water INFLUX

It has traditionally been assumed that the ratio of oil to water coming into the wellbore, after shut-in, is constant at the producing ratio. Theoretical considerations, suggest that the influx of liquid into the wellbore after shut-in is not a constant ratio, but is related to the oil and water's inflow performance relationship (IPR) and pressure. However, acoustic verification projects reveal that wellbore dynamics are much more complex than lPR suggests. In fact, quite often a net efflux of oil and/or water is observed rather than an influx.

6. Determination of Measured or Potential Efflux

Static gradients performed in the tubing of several verification projects have identified liquid (oil/water) segregation and movement with time. In some instances, oil rose to the top of the liquid column and the water migrated back into the formation. In other instances, water and oil were displaced totally by gas in the wellbore. The extent of this phenomenon depends on such characteristics as the gas inflow performance relationship, damage, and formation characteristics (relative permeabilities). Quantification of the efflux can only be done through verification projects or experience in similar wells.

7. Determination of In-Situ Liquid Volume Fraction

This fraction is what remains in the wellbore after the influx and efflux of the oil and water are taken into account, in addition to the oil and water contents at the time of shut-in. If this in-situ oil / water ratio cannot be quantified, a maximum possible error can be calculated by:

assuming the fluid is all oil
assuming the fluid is all water

The true reservoir pressure usually lies somewhere between these two extremes.

Note:

In many properly supervised AWS tests, the margin of error calculated is within very acceptable limits.

Conclusions

In order to have a successful survey, you need:

Proper design
Knowledgeable supervision
Understanding of wellbore dynamics