TPE

1. REPUBLIQUE DU CAMEROUN
Paix- Travail-Patrie
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MINISTERE DE L’ENSEIGNEMENTSUPERIEUR
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UNIVERSITE DE MAROUA
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FACULTE DES MINES ET DES INDUSTRIES
PETROLIERES
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DEPARTEMENT D’EXPLORATION MINIERE
PETROLIERE GAZIERE ET RESOURCES EN EAU
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REPUBLIC OF CAMEROON
Peace-Work- Fatherland
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MINISTRY OF HIGHER EDUCATION
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UNIVERSITY OF MAROUA
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FACULTY OF MINES AND PETROLEUM
INDUSTRIES
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DEPARTMENT OF MINING PETROLEUM AND GAS
EXPLORATION
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Tel: +237 653397589/656862354
THEME: SAMPLING PROBLEMATIC
Année Académique 2020/2021
ENCADREUR: Dr DOMRA KANA Xavier
DONNEES GEOLOGIQUES DE FORAGE ET FLUIDES DE
FORAGE
Tel :+237 653397589/656862354
Email: imip_uma@yahoo.fr
NAMES OF PARTICIPANTS
- SIHEU BEYO CEDRIC
- SO’OH MOUKOKO
- TANYI CLEMENTINE ADAH

2. INTRODUCTION
Sampling is defined as taking a small portion of a whole mass that
accurately represents the whole mass. Many general petroleum
engineering texts have sections covering the measurement of phase
behavior or pressure/volume/temperature (PVT) analysis, but few have
detailed descriptions of reservoir fluid-sampling practices. Our
assignment discusses the rationale for fluid sampling, general
guidance for establishing a sampling program, and some special cases
that go beyond the typical fluid sampling approaches. Sampling
problem can be define as obtaining a sample adequate for a given
investigation.

3. I. Overview
Pressure-volume-temperature(PVT) analysis, of fundamental importance to reservoir management,
measurements relating to corrosion potential, solids formation, and nonhydrocarbon constituents have the
potential to produce serious effects on:
• The design of production facilities;
• Compatibility with pipeline transport;
• Product sales value;
• Refinery maintenance costs;
• Reservoir asset values in general.
Fluid samples are thus required to enable advanced physical and chemical analyses to be carried out in
specialized laboratories. Samples must be collected from a wide range of locations such as:
• Separators;
• Pipelines;
• Tanks
• Wellbores;
• The formation.

4. This topic primarily targets the sampling of fluids under pressures above atmospheric, where numerous tools
and procedures have been developed that are essentially specific to the petroleum industry. Best practices are
proposed for fluid sampling, reporting of data, and quality control of samples.
Figure 1 is a schematic diagram illustrating some of the most common sources of error in relation to the
collection of production samples and data in the field.
Fig. 1 – A schematic view of wellsite sampling
and measurement error

5. The schematic in Fig. 1 emphasizes sampling activities in cased-hole wells, but pressurized samples are
also obtained with formation-test tools in openhole wells. Here, contamination by mud filtrate or excessive
pressure decrease (drawdown) during sampling means that it may not be possible to obtain quality PVT
samples. Contamination by oil-based mud (OBM) is especially problematic. Sampling from tanks or
pipelines also requires that care be taken to ensure that the fluid is representative of the location or
condition required to be studied.
II. Importance of reservoir fluid type
One of the principal variables in reservoir-fluid sampling is the type of reservoir fluid present. This is rarely
known with certainty and, in exploration wells, may be completely unknown at the start of testing.
Determining the exact nature of a reservoir fluid is, of course, a key objective of sampling and laboratory
study. Figure 2 shows the relation between the major classes of hydrocarbon reservoir fluid in terms of a
generalized phase diagram. Although the shape of the phase diagram is specific to the actual fluid
composition, it is the reservoir temperature compared to the temperature Tc of the critical point (Tc
determines if the fluid is an oil or a gas).

6. When the reservoir temperature is lower than Tc, the fluid is an oil and will exhibit a bubblepoint when
pressure is reduced into the two-phase region. If the reservoir-fluid temperature is above Tc, the fluid is a gas
and will either show gas/condensate behavior and a dewpoint on pressure reduction or, if the reservoir
temperature is also above the cricondentherm Tt, the fluid will behave as a one-phase gas with no liquid
formation in the reservoir on pressure reduction. If the fluid exists in the reservoir at or close to its critical
temperature, it is classified as a critical or near-critical fluid. These fluids exhibit neither bubblepoint nor
dewpoint, but on pressure reduction into the two-phase region, they immediately form a system comprising
large proportions of both gas and liquid (e.g., 60% gas and 40% liquid by volume).
Fig. 2 – A generalized phase diagram for reservoir fluids.

7. The reservoir pressure determines whether the fluid is at the boundary of the two-phase region (and
referred to as saturated) or at a higher pressure than the two-phase region (and referred to as
undersaturated). Saturated fluids will immediately enter the two-phase region when a well produces fluid
because of the reduction of pressure in the well and near-wellbore region. (See phase diagrams).
III. General guidelines for a sampling program
It may then be necessary to repeat some analyses during the appraisal stage, typically when wells
will yield samples that are more representative of likely production. In contrast, sampling late in
the appraisal phase may be needed only on occasions when surface measurements indicate
unexpected fluid character.

8. 1. Selecting sampling sites
The composition of subsurface water commonly changes laterally, as well as with depth, in the same
aquifer. Changes may be brought about by the intrusion of other waters and by discharge from and
recharge to the aquifer. Therefore, it is generally necessary to obtain and analyze many samples. Also, the
samples may change with time as gases come out of solution and supersaturated solutions produce
precipitates. Sampling sites should be selected, if possible, to fit into a comprehensive network to cover an
oil-productive geologic basin.
2. Determining measurements required
The first priority in developing a sampling program, whether extensive or limited, is to establish
exactly what measurements are required. Generally, it is advisable to plan to perform all applicable
measurements unless sufficient information is already available from earlier tests of other wells. The fact
that a measurement proves to be "normal," or an unwanted component is not detected, should not be
regarded as a waste of resources because it can still provide essential information, especially if data are
different on other wells or changes are identified during production. On-site measurements are
recommended for all reactive components because concentrations may change with time (e.g., during a
well test), and losses frequently occur during sample transport and storage.

9. 3. Set up a suitable sampling program
Having decided which fluid measurements are required, it is necessary to set up a suitable sampling
program, taking into account the cost of the work, the quality and quantity of samples and subsequent
measurements, the urgency with which data are required, and the application of safe practices. Thus, in
the case of a well test, the overall plan should include the following:
 Establish the production potential
 Determine the permeability
 Determine the skin
 Collect fluid samples
 Each objective should be defined in sufficient detail so that all parties involved are fully aware of
their obligations, thus increasing the likelihood of achieving the objective. Objectives must be
realistic and must allow for possible changes.
 Fluid-sampling operations are often handled by service-company personnel, but because significant
variation in levels of competence exists within the industry and within service companies themselves,
themselves, it is recommended either to use specialist laboratory personnel or to supervise the
service-company operations closely.

10. 4. Sampling overview
Surface-separator sampling is the most common technique, but the reservoir-fluid sample
recombined in the laboratory is subject to errors in the measured GOR and any imprecision
in the laboratory recombination procedure. Downhole samples (or wellhead samples) are
not affected by such inaccuracies but require the fluid to be in monophasic condition when
sampled; this can be confirmed definitively only afterward in the laboratory. Also, there is
general reluctance to attempt downhole sampling in gas/condensate reservoirs because
many are saturated, and the phases are likely to segregate in the wellbore. The ideal
situation for a laboratory is to receive both surface and downhole samples because a choice
is then available, and a good idea can be obtained of how representative the resulting fluid
is. In certain circumstances, it can be good practice to collect "backup" fluid samples at the
earliest opportunity during a production test, even if a well has not cleaned up properly.

11. If there is concern about whether the fluid is homogeneous in a flow line or tank, the best
approach is to take samples from different locations and compare them. In a liquid flow line, take
samples from the top and bottom; in a tank, take samples at different depths. If samples are
indeed different, it is advisable to locate a better sampling point (e.g., where there is sufficient
turbulence to homogenize the fluid). Failing this, the only solution may be to mix the samples
together in an attempt to provide a representative average fluid. If, however, the purpose of the
sampling is to study the nonhomogeneity, then separate samples should be taken accordingly.
When samples are collected from drillstem tests (DSTs), which do not involve surface
production, the limited volume of fluid produced from the reservoir may be insufficient to
remove mud filtrate or other contaminated or changed fluid. Thus, even samples collected from
the last fluid that enters the drillstem may not be truly representative. This is especially the case
for formation-water samples, which are more widely susceptible to contamination from drilling
fluids, well-completion fluids, cements, tracing fluids, and acids, which contain many different
chemicals. The most representative formation-water samples are usually those obtained after the
oil well has produced for a period of time and all extraneous fluids adjacent to the wellbore have
been flushed out.

12. 5. Sampling procedures
Sampling procedures differ based on whether the fluids are pressurized or not. For
applicable procedures as follows;
 Downhole fluid sampling
 Surface sampling of reservoir fluids
 Nonpressurized hydrocarbon fluid sampling
 Oilfield water sampling
6. Additional considerations
 Measurements affecting reservoir fluid sampling
 Quality control during reservoir fluid sampling
 Fluid sampling safety hazards

13. IV. Special topics and considerations in fluid sampling
1. Sampling of crude-oil emulsions
Samples of emulsions may be required for several reasons, including
 Verifying crude specifications
 Evaluating the performance of emulsion-treating systems
 For laboratory testing such as choice of demulsifiers and optimum concentration
Emulsions frequently must be sampled under pressure, and special procedures must be
used to obtain representative samples. For crude specification testing, it is not important to
maintain the integrity of the water droplets; however, the sample location point may be critical.
In general, samples should not be withdrawn from the bottom of the pipe or vessel, where free
water may accumulate, affecting the BS&W reading and, thus, the validity of the sample. In
addition, the sample should not be withdrawn from the top of the vessel or pipe, as it is likely
to contain primarily oil. The best position in the pipe to take an emulsion sample is from the
side at approximately midheight, preferably with a sampling probe (often known as a "quill").
Choosing a sampling point at which there is turbulence and high fluid velocity in the pipe may
also avoid problems caused by segregation and ensure that the sample is homogeneous.

14. Also, emulsions exhibit a wide range of stability, so samples of emulsions collected in
the field may separate partially or even totally during shipment to the laboratory.
The best sampling procedure to use for samples from pressurized sources, without
further emulsification of the liquids, is the technique based on a floating-piston cylinder,
as described in Surface sampling of reservoir fluids. A setup similar to that in Figure 3 is
used, with the hydraulic section of the cylinder filled with a pressurizing fluid (e.g., a
glycol/water mixture or a synthetic oil) and the top of the cylinder evacuated. Purging of
the sample line can be made but should be carried out at a bleed rate. The sample
collection should be performed slowly to obtain the sample with a minimum pressure
drop between the cylinder and the sampling point. Alternative methods use a simple
sample cylinder (without any floating piston), which is initially filled with water (or
mercury). Once the pressurized sample is captured, the cylinder can be depressurized, if
required, by removing further quantities of hydraulic fluid extremely slowly with little
effect on the sample

15. In situations in which sampling into a pressurized container is not possible, the
best method to take an emulsion sample is to bleed the sample line very slowly into the
sample container. The idea is to minimize shear and reduce emulsification that may be
caused by the sampling procedures.
Fig. 3 – Diagram of a liquid-sampling apparatus.

16. 2. Waxy and asphaltenic fluids
Great care should be taken in sampling fluids that have potential for the precipitation of wax or
asphaltenes because loss of a solid or flocculated phase during sampling or handling will produce
fluids that are no longer representative. Because these tendencies may not be recognized until the
samples are being studied, the same precautions are advisable for all fluids that have not been
characterized previously in detail.
Asphaltene problems in particular are difficult to predict owing to a poor correlation between
asphaltene concentration and flocculation tendency. Because of the difficulty of homogenizing fluids
containing flocculated asphaltenes, it is highly recommended that downhole samples be collected
using single-phase samplers with the pressure raised well above reservoir pressure by the nitrogen
charge. Separator oils and atmospheric oils generally suffer from limited asphaltene deposition
problems because they contain very few of the light hydrocarbons that contribute to flocculation.

17. Paraffinic or waxy crude oils can be extremely difficult to sample, with separator liquids
occasionally solidifying in sampling lines and equipment, and the use of heated, short, large-diameter
sampling lines is recommended. At downhole temperatures, sampling is generally easier, and limited
availability of heated sampling tools exists. Single-phase sampling tools can be used, especially if
asphaltene and wax problems may occur, but pressure maintenance alone will not prevent wax
precipitation on cooling, as this is strongly dependent on temperature. Though rarer, gas/condensate
reservoirs can also produce liquids that show wax-forming tendencies, which require special handling
procedures
3. On-site measurements
It is worth giving some details of common on-site measurements because they must be
performed on representative samples or sample streams and are frequently included in sampling
programs.
The most common on-site gas analysis method is the "length-of-stain" detector tubes (often
called "sniffer" tubes or Drager tubes, after one of the suppliers) used primarily for H2S but available
for CO2 and a wide range of other gases and vapors. This method is relatively simple to use, and
principal errors derive from incorrect use of response factors or stroke counts.

18. The ASTM has a number of standards that apply to this method, and all propose a
sampling system based on a modified polythene wash bottle (or equivalent setup) to
ensure that measurements are performed on a representative sample stream. Flexible
tubing is connected from a control valve at the sample point to the wash-bottle delivery
tube, and the screw cap is removed (or perforated). Then, the control valve is opened
slightly to allow gas to flow into the bottom of the wash bottle, which purges air out of the
top.
After purging for at least 3 minutes, the length-of-stain detector can be inserted
through the top of the wash bottle and the pump operated to perform the measurement.
This arrangement ensures that the gas sampled is at atmospheric pressure. Detector tubes
have a limited life and should not be used beyond the date limit. Care must be taken to
avoid contacting any liquids with the end of the tube. An alternative approach used a gas
bag, which must be made from an inert material and purged completely at least five times
immediately before the measurement. In some circumstances, gas concentrations above
the detector-tube limit can be estimated by using fewer or fractional pump strokes, but
such practices must be recorded clearly to help interpret measurements. For reactive
species like H2S, there is significant justification for making on-site concentration
measurements by two independent techniques, as this provides on-site quality assurance.

19. Portable gas chromatographs are becoming more common at the
wellsite, and they bring the advantage of early characterization of gas
composition, together with an identification of most nonhydrocarbons
present (depending on the carrier gas used). However, such instruments are
accurate only when operated by trained personnel and when properly
calibrated. Also, the additional cost of the service must be justified, though
this could occur in the following cases:
 high nitrogen or helium is anticipated,
 early decisions must be made on the basis of gas sales value,
 variable nonhydrocarbon concentrations occur within a field and will contribute to
property mapping or be used to determine if fluid sampling is required,
 sample transport logistics mean that laboratory analyses may take a very long time.

20. 4. Drilling-mud gas
During drilling operations, returning drilling mud is commonly monitored for the
presence of hydrocarbons, both for formation-evaluation purposes and for safety concerns.
Generally, hydrocarbons are extracted from the mud to provide an air sample containing
hydrocarbons, and as the extraction technique is dependent on equipment design and
installation, measured compositions are rarely quantitatively representative of the
concentrations in the drilling mud. This limitation is commonly accounted for by the use of
hydrocarbon ratios when interpreting drilling-mud hydrocarbon analyses and logs, but it
has been shown that effective quantitative measurements can be obtained with careful
location of the mud-sampling point, the use of a special extraction device, and care to
account for losses of hydrocarbon gas from the return line before the mud-sampling point.
Mud logging is covered in detail elsewhere in this Handbook.

21. 5. Water-cut measurements
Downhole sampling can be used as a means to measure water cut in producing oil
wells, especially when there are no separation facilities or suitable measuring
instruments at the wellsite or when measurements with depth are required as an
alternative to (or validation for) production logs. In these cases, the well should be
flowing at normal producing conditions, unless the purpose of the sampling is to
investigate the water cut at other production conditions. As in all cases in which
sampling is attempted from two-phase flow, there is the potential for preferential
collection of one of the phases; this is especially likely if the two phases are not well
distributed. It may be advisable to set the sampler to collect the sample in the shortest
time to minimize any segregation. Care also should be taken in high-angle well sections,
where the sampler will lie in the lowest part and is likely to sample water preferentially.

22. For a measurement of total water cut, it is advisable to sample from a depth a
moderate distance [e.g., 20 ft (6 m)] above the top of the perforated interval. Also, it is
good practice to take a number of separate samples under identical flow conditions to
allow evaluation of the repeatability of water-cut measurements. Good agreement between
replicate samples, although not absolute proof, gives high confidence in the reliability of
the measurements, whereas significant variation is a clear sign of unrepresentative
sampling or of variable water cut in the fluids entering the wellbore. Sampling from a
range of depths both above and within the perforated interval in a well can provide more-
detailed information on water production, but it does not give production-rate information
on its own.
Volumetric measurement of water cut should ideally be made on site so that repeat
measurements can be made as required. If emulsion is present in the sampled fluid, this
should be given time to break, or suitable chemicals should be used to demulsify the
sample before the definitive water-cut measurement

23. V. Future developments
Optimizing costs in all petroleum-industry activities continues to have a major effect on
sampling operations, with competition between production testing and formation-test-tool
operations leading to widespread industry acceptance of lower-quality fluid samples from the
latter. A key challenge at present is to get better-quality formation-test-tool samples not simply
by advanced tool capability but by better planning and preparation for the test. Increasing
efforts to obtain reservoir information from short well cleanups is also putting pressure on fluid-
sampling operations, but in some cases (such as on-site measurements), this change in
emphasis may provide opportunities for measurements that otherwise would not be available.
Multiphase metering is likely to have an increasing impact on sampling operations because
the accuracy of flow-rate measurement is seen to be improving, and the economic benefits of
avoiding the use of separators will be major. However, even with significant development of
special sampling approaches (such as isokinetic sampling), it seems unlikely that the same
quality of samples will be available as with traditional separator methods.

24. conclusion
Both the reservoir-fluid type and the saturation condition influence the way fluid samples
must be collected, yet this information can be estimated only at the time of the sampling
program and is especially uncertain when fluids are close to the boundaries between the
different types. Numerous correlations are available for estimating reservoir-fluid type and
condition from produced-fluid flow rates and properties measured at the wellsite (such as
those developed by Standing), but you should be careful in using these methods, especially
when the fluid properties differ significantly from those used to develop the correlation. For
this reason, it is good practice to allow for significant error in the reservoir-fluid character when
designing and implementing sampling programs. With the tremendous pace of the
development and functionality of new downhole tools, there is a need for speedy updating of
industry standards documentation to allow broad dissemination of new sampling knowledge
and practices; however, it is clear that this is not a role readily filled by traditional standards
organizations such as API. Working groups and forums involving service companies and
operators may provide the best prospect of developing standards updates, which can be
published in peer-reviewed petroleum engineering journals.

25. References
 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.
http://dx.doi.org/10.2118/49067-MS
 Williams, J.M. 1998. Fluid Sampling under Adverse Conditions. Oil & Gas Science and
Technology - Rev. IFP 53 (3): 355-365. http://dx.doi.org/10.2516/ogst:1998031
 Standing, M.B. 1951. Volumetric and Phase Behavior of Oil Field Hydrocarbon Systems, 10–
19. Richardson, Texas: SPE.
 ASTM D4810-88(1999) Standard Test Method for Hydrogen Sulfide in Natural Gas Using
Length-of-Stain Detector Tubes. 1999. West Conshohocken, Pennsylvania: ASTM
International. http://dx.doi.org/10.1520/D4810-88R99
 ASTM D4984-89(1999) Standard Test Method for Carbon Dioxide in Natural Gas Using
Length-of-Stain Detector Tubes. 1999. West Conshohocken, Pennsylvania: ASTM
International. http://dx.doi.org/10.1520/D4984-89R99