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Measurements affecting reservoir fluid sampling

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In the same way that laboratory measurements require representative samples to be meaningful, reservoir fluid samples themselves must be supported by accurate data to provide a unique identification and to record all important production and sampling parameters that will be used in checking the sample and (in many cases) in determining the exact measurements that will be performed. This article reviews the importance of data measurement and provides guidelines for recording and validating the necessary data.

Types of errors

Provided that flowmeters and pressure gauges are properly sized for a measurement, so that readings are not made at the low end of the measurement range, random errors are generally small. Systematic errors are a major concern, however, for all measurements, deriving from sensor malfunction, poor (or lack of) calibration, and human error in general; the latter item can include both errors in recording and reporting data and those deriving from the use of computer-based acquisition systems, for example:

  • Entry of erroneous calibration data
  • Incorrect sensor connections
  • Software bugs

Although systematic errors are comparatively rare, their magnitude can be significant. In fact, on some occasions, errors are identified only when measured values are so large that the values become ridiculous.

Measuring gas/oil ratio accurately

The gas/oil ratio (GOR) is considered to be the most important measurement for separator samples, and it is dependent on errors in both the gas flow rate and the oil flow rate, which are measured separately. New techniques have seen limited application to reduce errors in GOR, such as the injection of a standard marker chemical upstream of the separator and measurements of the concentrations in the separated gas and liquid streams. Also, use of various carry-over measurement techniques has been made, such as the isokinetic approach described briefly earlier. However, significant improvements can be achieved simply by proper sizing, calibration, and recording.

Measuring gas rate accurately

In production testing, gas flow rate itself is widely measured by the orifice meter. This system has been in use for a long time, but new standards have been issued more recently that improve gas rate calculations.[1] The orifice meter relies on a range of coefficients or factors to calculate the flow rate from the differential pressure measured across the orifice. Many of these factors are derived from on-site measurements of the gas. The measurement accuracy can be improved by ensuring that the orifice plate has been sized correctly for the flow so that it falls within 30 to 70% of full range (or higher, if there is no chance of going off scale). Likely additional sources of error come from what could be considered mechanical factors, such as the physical condition of the orifice plate itself; waxy deposits or damage will change the flow performance and can lead to significant errors. An obvious but commonly overlooked potential error concerns not the condition of the orifice, but the recording of the orifice size. An oversight here can have serious implications not only for fluid analysis but for well-test interpretation. Errors in the differential-pressure measurement derive primarily from poor calibration of the recording instrument or from liquid buildup in the lines that have not been purged. The orifice meter pressure-base factor is a common source of errors because variations do exist between the reference pressure and temperature used for gas measurements (e.g., a variation between 100 kPa and 14.7 psia is an increase of 1.4%). Thus, it is essential that reference conditions are quoted correctly. The actual source of gas gravity and supercompressibility factors (Fg and Fpv) is usually not important for fluid studies because accurate values are commonly calculated in the laboratory on the basis of compositional analysis of the gas sample, but it is necessary to know exactly which values were used to correct gas flow rate to the new values. To ensure the highest accuracy in gas flow-rate measurement, a check should be made that all the meter factors are determined and used correctly. Approximate flow rates can be derived from the choke setting, and a comparison should identify any major error in the orifice meter calculation.

Errors in measuring oil rate

Condensate or oil flow rates are normally measured by a positive displacement meter that is placed in the outlet line from the separator upstream of the flow control valve. The most common error derives from incomplete reporting of the measurement conditions for the oil rate, especially whether the oil flow is measured at separator or at stock-tank conditions, and the meter factors and shrinkage values that should be applied if stock-tank rates are reported. The most likely causes of error in the measurement itself are poor calibration, worn seals (allowing liquid to bypass the measuring element), or the release of gas leading to high-volume, two-phase measurement. The latter problem can be treated by the installation of a "gas eliminator," which is effectively a tiny separator before the meter. Gas breakout in the meter may be signaled by sudden flow-rate fluctuations, whereas stable foams with some oils (occasionally referred to as "carry-under") may be less obvious and may require antifoaming agents to overcome. Any water and sediment in the oil flow should be determined by the Basic sediment and water (BS&W) measurement and corrected for accordingly. It is good practice to size the flowmeter according to the expected flow rate, as recommended for gas flows. Flow rates also should be checked by gauging the stock tank regularly.

BS&W error

Basic sediment and water (BS&W) measurement is performed by centrifuging a sample of liquid mixed with solvent; although relative error in the measurement can be very important at low BS&W, measurement accuracy is generally adequate for the purposes of flow-rate correction. Of more concern is whether the sample used for the measurement is representative, so samples should be taken from the top and bottom of the liquid flowline, and a comparison should be made.

Shrinkage factor error

The shrinkage factor, used to relate separator-liquid volumes to stock-tank conditions, depends on a differential liberation of gas and may give different values from the true flash process as separator liquid enters the tank stage. In normal circumstances, it is thus much better to rely on a separator flow rate measured with a calibrated meter than to use the tank flow rate corrected according to the shrinkage tester. In the worst case, with no reliable liquid flow rates at separator conditions, an experimental shrinkage factor must be determined in the laboratory and used with the average tank flow rate to obtain the necessary rate.

Checklist for surface measurement data

Further details of proper oil- and gas-measurement practices are available in other sources.[2][3] Table 1 provides a checklist that can ensure that surface-measurement data are as reliable as possible. Other surface measurements should be validated in similar fashion; for example, wellhead pressures should be measured with a dead-weight tester or with a pressure gauge that has been calibrated recently.

Measuring reservoir temperature accurately

Among the downhole measurements, it is the reservoir temperature that is the most important for fluid studies because this is the temperature at which reservoir-fluid-property measurements will be made. In addition, pressures, gradients (density, pressure, and temperature), and, indeed, the depth at which these measurements are made are all important in validating samples and in interpreting laboratory measurements. Downhole temperature and pressure gauges should be calibrated, under well conditions if possible, and adequate time allowed for temperatures to stabilize if fluid production or injection has influenced downhole temperatures. Good knowledge of temperatures in a reservoir may only be available once measurements have been made in several wells.

Essential sampling data

The data listed in Tables 2 and 3 must be considered essential if fluid samples are to be studied properly in the laboratory. These data are the absolute minimum needed for valid laboratory studies. Every attempt should be made to provide all the information requested on sampling sheets. An independent check at the wellsite is advisable to ensure that sampling personnel have achieved this need. Many additional measurements are of value in sample validation, and measurement trends with time are important in monitoring well behavior (such as during cleanup or when evaluating the effect of changes in production). To enable a proper check to be made of well conditioning, separator stability, and data recorded on the sampling sheets, it is recommended that a full copy of the well-test report (or records of production data for production facilities) be sent to the laboratory that will be working on the samples.

Measuring water properties

Water can be produced in a surface separator—either from liquid water in the zone being tested or by condensation from water vapor in the produced gas, or possibly from both—and can affect measurement accuracy. The effect of water on gas gravity (and, thus, the gas flow rate) is currently ignored because it is not routinely measured either in the field or in the laboratory. In most cases, this is an acceptable approach, but in separators operating at high temperatures and low pressures, the water content of the gas stream can reach significant proportions (for further details, refer to the nomogram[4] "Water content of hydrocarbon gas"). Water production can have more serious consequences if separator-liquid flow rates are not properly corrected for BS&W measurements.

The data in Table 4 should be recorded for the sampling of water from a well. Similar data should be recorded for water samples taken from other installations or facilities.


  1. Teyssandier, R.G. and Beaty, R. 1993. New Orifice Meter Standards Improve Gas Calculations. Oil Gas J. 91 (2): 40
  2. Williams, J.M. 1998. Fluid Sampling under Adverse Conditions. Oil & Gas Science and Technology - Rev. IFP 53 (3): 355-365.
  3. GPSA. 1987. GPSA Engineering Data Book, Vol. 2, Fig. 20-3. Tulsa, Oklahoma: Gas Processors Suppliers Association.
  4. Moffatt, B.J. and Williams, J.M. 1998. Identifying and Meeting the Key Needs for Reservoir Fluid Properties A Multi-Disciplinary Approach. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 27-30 September. SPE-49067-MS.

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See also

Fluid sampling

Quality control during reservoir fluid sampling

Fluid sampling safety hazards