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Preparing for fluid sampling

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Once a fluid sampling program has been defined, it is essential to prepare the well and to select and prepare the sampling equipment. This article discusses those aspects of establishing a fluid sampling program.

Well conditioning

The best way to prepare a well for sampling is dependent on the reservoir-fluid type, as indicated earlier. With the exception of one-phase gas reservoirs, prolonged production will cause all reservoirs to reach saturation conditions, thus bringing about changes in the fluid composition throughout the reservoir. When this happens, there is no longer any possibility of obtaining truly representative fluid samples. Thus, although in one-phase gas reservoirs (and for a certain length of time in undersaturated reservoirs), the fluid will remain unchanged during pressure depletion—the true nature of the fluid will be unknown until samples actually have been analyzed in a laboratory—it is strongly recommended to take samples at the earliest opportunity in the life of a well.

Both in openhole and in cased-hole completions, the best depth or production interval for sampling will be as far away as possible from gas/oil, gas/water, and oil/water transition zones to reduce the chances of coning. Every attempt should be made to test zones individually because commingled production may be difficult to detect and is impossible to correct in the laboratory.

The possible influence of any matrix-treatment chemicals on sampling programs should be evaluated, and treatment schedules should be modified accordingly. Problems such as the liberation of carbon dioxide (CO2) or H2S after acid treatments are possible, as is the release of other components such as metal ions, and these could affect analyses. On the other hand, sampling after an acid treatment has been properly cleaned up has the probable advantage of reduced drawdown in the near-wellbore region.

Because of the enormous variety of constraints, there can be no definitive guidelines for well conditioning. The first phase of conditioning involves the cleanup, in which the well is flowed to the surface to remove any solids resulting from perforating activities, drilling mud or completion fluids in the well, and mud filtrate or workover fluids that may remain in the formation near the wellbore. Here, the production rate must provide a sufficient flow velocity in the production string to lift solids, hydrocarbon liquids, and water to the surface, but conditioning is typically performed at the maximum rate, as this reduces the total length of the cleanup period.

The cleanup period typically lasts from a few hours to 24 hours, and progress is monitored by regular measurements of flowing wellhead pressure, basic sediment and water (BS&W), and other parameters. At the end of the cleanup period, production may be diverted through the separator to check its operation. This is an ideal moment to take backup samples.

Conditioning procedures

Depending on the fluid type, significant differences can exist in conditioning procedures, which attempt to control or eliminate any modified reservoir fluid so that fluid entering the well is identical to that in the reservoir. For an unknown fluid, one of the most important considerations is the need to interpret the response of the well to different flow conditions and then develop the final sampling program during the test itself on the basis of this information. If initial production indicates an oil, the best approach is to evaluate the response of surface gas/oil ratio (GOR) to changes in production rate. As long as representative reservoir fluid enters the wellbore and is carried to the surface, and the same separator operating conditions of temperature and pressure are maintained, the GOR should remain stable for different choke sizes. A GOR that changes significantly between choke sizes is indicative of nonrepresentative production either caused by two-phase flow effects in the near-wellbore region or possibly by commingled production of more than one reservoir fluid (e.g., oil zone and gas cap), and production should be choked back until GOR no longer changes with choke size.

If, however the reservoir contains a saturated gas condensate, extra flow periods will simply compound the condensate-buildup problem, so sampling at the earliest stable rate is probably advisable. In fact, some modeling work[1] has shown that when an important ring or bank of condensate has built up in the reservoir, it may be possible to produce at reasonably high rates with an apparently stable GOR while producing fluid that is not representative of the original reservoir fluid. At very high flow rates, the GOR may appear to increase as a result of liquid carry-over in the separator gas stream.

Gas wells

Gas wells that have a small flow velocity will exhibit liquid "slippage" in the tubing and heading or unstable flow rates at the surface. Several methods of establishing the required minimum flow rate are available, of which an industry nomogram[2] has been used extensively. In very-low-permeability, saturated gas/condensate reservoirs, it may not be possible to lift condensate from the well without creating a major pressure drawdown in the reservoir and causing nonrepresentative fluid to enter the wellbore. The best approach here is to select a small tubing diameter before the test so that the minimum lift velocity can be achieved with a low flow rate and, thus, reduced drawdown.

Highly undersaturated reservoirs

In highly undersaturated reservoirs, it is possible to take downhole samples while the reservoir is producing, provided that the downhole flowing pressure is greater than the fluid saturation pressure. In many cases, however, the saturation pressure will be unknown or cannot be estimated with sufficient accuracy; then, the best recommendation for downhole sampling in an oil reservoir is to sample when shut in, as for reservoirs that are at or close to saturation pressure. Before downhole sampling with the well shut in, it is necessary to allow pressure to build up near to static and then to purge fresh reservoir fluid at a low rate to replace any "changed" fluid in the wellbore or in the near-wellbore region. The most suitable time for downhole sampling during the well test is probably after the initial cleanup and buildup, but an alternative is at the very end of the test if a long buildup is part of the test plan.

Oil based mud used for drilling

On a different aspect of well conditioning, the use of oil based mud (OBM) during drilling operations can lead to contamination of the near-wellbore region, and any subsequent contamination of fluid samples by base oil may not be identified. This is unlikely to pose a problem if the well is properly cleaned up, but it can result in significant contamination if samples are collected using an openhole formation tester in which only small volumes are purged. It is thus best if lost circulation can be minimized during drilling and ideal if only water-based muds are used.

When surface sampling is planned

If surface-separator sampling is planned, another form of conditioning can be necessary if chemicals are in use. Injection of methanol or glycol upstream of the separator can be used to prevent gas-hydrate formation, and the injection of antifoaming agents and demulsifiers may be required in oil reservoir fluids. If possible, any such injection should be stopped before separator samples are taken, and enough time should be allowed for such potential contaminants to be purged from the separator (e.g., by waiting at least five times the residence time).(See Oil and gas separators)

Importance of separator conditions

Separator conditions themselves also have an influence on sampling operations. Separator temperature can be controlled only by changing the production rate or by the use of a heater, but there is generally more flexibility in the separator pressure, which can be set at any value not exceeding the choke downstream pressure limit for critical flow (or the working pressure of the separator, if it is lower). The advantages of using the highest-acceptable separator pressure include more intermediate components being in the liquid (increasing the liquid flow rate somewhat), more gas in sample bottles because of the increased pressure, and generally a leaner gas stream with less condensation on cooling. Although service companies may be reluctant to operate separators at higher pressures, these benefits can be important for the quality of fluid measurements. For low-GOR oil production, a lower separator pressure may be advisable because it can significantly increase the gas flow rate and improve its measurement accuracy. Separator liquid levels also can be adjusted in many separators; lower levels increase gas residence time and thus can reduce carry-over problems for gas wells, whereas higher levels increase oil residence time, which can reduce emulsion or foaming problems.

Best practices for well conditioning

In view of the concerns presented above, the current best practices for conditioning a well for sampling should include the following steps. Complementary details of guidelines can be found elsewhere.[3][4]

Oil reservoirs

For oil reservoirs:

  • Clean up the well until wellhead pressure and BS&W stabilize.
  • For surface sampling, reduce the flow rate in steps until the separator GOR does not change between choke sizes, then stabilize separator conditions and take separator samples.
  • For downhole sampling, shut in the well and build up to static pressure; produce at a low rate for long enough to remove all changed material in the near-wellbore region, and briefly shut in.
  • Finally, purge fluid past the sampler in the well at a bleed rate and shut in before sampling (this step may be omitted if downhole fluid is known to be monophasic).

Gas/condensate reservoirs

For gas/condensate reservoirs:

  • Clean up the well until wellhead pressure and BS&W stabilize, then flow the well at the lowest flow rate that will lift liquids up the tubing.
  • For surface sampling, stabilize separator conditions and take separator samples.
  • For downhole sampling (undersaturated reservoir with monophasic flow downhole), collect downhole samples.

Near-critical fluid reservoirs

Recommendations for well conditioning in a near-critical-fluid reservoir are not widely available, both because these reservoirs are fairly rare and because there is no sure way of identifying the situation from surface measurements. A rule of thumb is that reservoirs with near-critical fluids often exhibit separator GORs in the region of 4,000 scf/bbl (700 m3/m3), but there are no well-established GOR ranges for the near-critical region, and correlations are rarely applicable in this area. Because pressure drawdown can result in major changes in the reservoir fluid, it is advisable to perform sampling at the earliest moment (a good practice for all reservoir types) and to condition the well by flowing it at successively slower rates to remove all nonrepresentative hydrocarbon phases as far as possible. However, it may be difficult to establish when the well is adequately conditioned because the surface GOR may change only slightly with different quantities of downhole phases, and expert advice should be sought to evaluate all the observations.

Selection and preparation of sampling equipment

Equipment planning must start as soon as the sampling program is defined to ensure that all necessary equipment will be available and checked well in advance of the sampling operation. For pressurized sampling operations, metal cylinders are invariably used, almost always with valves at each end that facilitate filling, transfer, and cleaning operations. For downhole samples and separator liquid samples, the sampling procedure requires maintaining pressure on the sample while the sample cylinder is filled. Achieving this by draining mercury from a full cylinder[5] has been largely discontinued owing to the safety and environmental concerns with mercury. The industry is now using piston cylinders, which have an internal piston to separate the sample part of the chamber from the hydraulic fluid (commonly a mixture of water and ethylene glycol). Maintenance of the piston cylinders is more complicated because the piston seals must be in excellent condition to prevent the occurrence of internal leaks.


Cylinders are commonly made from stainless steel or titanium, the latter being significantly lighter and offering better resistance to H2S (while being incompatible with mercury). Aluminum cylinders are in common use because larger volumes of sample are generally required, and the cylinder weight is a concern. Cylinders with internal coatings, such as Teflon® * , are also used occasionally. The wide variety of materials used for pressurized sampling demonstrates the fact that there is no perfect solution to the problems of resistance to corrosion, sample preservation, volume, and weight. All cylinders must be provided with plugs for the valves, end caps to protect the valves, and storage containers to facilitate handling and to protect cylinders during transport. It is good practice to plug and label cylinders when they have been prepared for sampling to avoid any confusion when at the job site.* Trademark of DuPont Corp., Wilmington, Delaware

Atmospheric containers

For atmospheric samples, containers that are used for water samples include polyethylene, other plastics, hard rubber, metal cans, and borosilicate glass, but the choice should be based on the measurements that will be performed on the samples. For stock-tank hydrocarbon liquids, glass or plastic containers are more resistant to corrosive components and are generally preferred for smaller volumes. Although plastic containers are more robust, they can contaminate samples with plasticizers, and glass bottles must be used for storing stock-tank samples intended for geochemical analysis. Glass containers must be well protected against the risk of breakage.

Water containers

For water samples, glass will adsorb various ions such as iron and manganese and may contribute boron or silica to the aqueous sample, so its use should be avoided if ionic analyses are required. Plastic and hard rubber containers are not suitable if the sample is to be analyzed to determine its organic content, and a metal container is often used if the sample is to be analyzed for dissolved hydrocarbons such as benzene. Otherwise, a polyethylene bottle is probably the most satisfactory container, especially if the sample is to be stored for some time before analysis. Also, a plastic container is less likely to break than is glass if a water sample is transported in freezing temperatures. However, not all polyethylenes are acceptable because some contain relatively high amounts of metal contributed by catalysts in their manufacture. The approximate metal content of the plastic can be determined by a qualitative emission spectrographic technique.

Other sampling considerations

In addition to sample containers, sampling equipment must include fittings, valves, gauges, and lines to enable samples to be recovered safely from the required location. Trained personnel must be assigned to collect samples. They should have copies of the sampling program and field procedures, the prepared forms for recording data, and a supply of labels. All sampling equipment must have been previously pressure tested and be clean and dry. Downhole-sampling equipment such as production samplers and formation-test samplers are extremely sophisticated and must be prepared by specialists. Great care must be taken with maintenance, cleaning, and assembly to ensure the maximum chance of correct operation and the minimum chance of contamination or other nonrepresentative sampling.


  1. McCain, W.D. Jr. and Alexander, R.A. 1992. Sampling Gas-Condensate Wells. SPE Res Eng 7 (3): 358-362. SPE-19729-PA.
  2. Turner, R.G., Hubbard, M.G., and Dukler, A.E. 1969. Analysis and Prediction of Minimum Flowrate for the Continuous Removal of Liquids from Gas Wells. J Pet Technol 21 (11): 1475–1482. SPE-2198-PA.
  3. 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.
  4. API RP 44, Sampling Petroleum Reservoir Fluids, second edition. 2003. Washington, DC: API.
  5. API RP 44, Sampling Petroleum Reservoir Fluids. 1966. Washington, DC: API.

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See also

Fluid sampling