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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. This article 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.
- 1 Overview
- 2 Importance of reservoir fluid type
- 3 General guidelines for a sampling program
- 4 Special topics and considerations in fluid sampling
- 5 Future developments
- 6 References
- 7 Noteworthy papers in OnePetro
- 8 External links
- 9 See also
- 10 Category
An enormous range of reservoir fluids exists, and this means that the limited measurements of produced oil and gas properties that can be made in the field are far from adequate to provide the detailed characterization that modern petroleum engineering requires. In addition to 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
The lack of such data could easily represent more risk than that tolerated when the decision to perform sampling and laboratory studies is taken. Examples of the financial impact of errors in fluid-property measurements are given elsewhere. 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:
- The formation
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.
Reservoir-fluid-property measurements derive from a complicated series of processes relying both on the operation of equipment and the performance of people, so the scope for errors is very significant. The overriding challenge in fluid sampling is that of ensuring that the fluid entering the sample container is representative of the bulk fluid being sampled. It is equally important that the sample remains representative during handling and storage, until all required measurements have been completed. Although thorough sample-checking procedures can identify some of the most obvious problems, there is never absolute certainty that the fluid under study is truly representative of the reservoir fluid. On occasion, laboratory measurements can show that a fluid is definitely not representative (e.g., saturation pressure is significantly higher than reservoir pressure), but even here the problem could lie with errors in field measurement data rather than with the samples themselves. Thus, it is essential that all the necessary precautions are taken to prevent poor samples from leading to erroneous physical-property measurements.
Fig. 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. Perhaps the most important, yet often misunderstood, phase of any sampling program is that of well conditioning. A poorly conditioned well may still be producing drilling-mud filtrate, workover fluids, or reaction products and, in extreme cases, such materials may remain even after months of production. A conflicting aim of well conditioning is to avoid excessive pressure drawdown and the creation of a large region of two-phase reservoir fluid around the wellbore, which may be difficult to remove. This is especially important in the case of gas/condensate reservoirs, of which many are found at their saturation pressures. The sampling program must ensure that appropriate procedures are used to ensure that samples are taken under the best conditions.
Fig. 1 – A schematic view of wellsite sampling and measurement errors.
Measurements of reactive or nonhydrocarbon components of reservoir fluids are complicated by the potential for loss through reaction or adsorption in contact with the production tubing or with sample-bottle walls, especially during long storage periods. On-site measurements can be very important if performed and recorded properly.
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.
Not only may errors in the field mean that samples are not fully representative of the reservoir fluid, but even good fluid samples may be studied under invalid conditions. Pressure and temperature errors can influence measurements and their interpretation, but it is especially errors in gas/oil ratio (GOR) that can have a major influence on a PVT study. Even basic data, such as sampling date and time, if not recorded or erroneous, can reduce the value of samples, even to the point of making measurements meaningless.
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. Fig. 1 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). 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).
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)
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.
General guidelines for a sampling program
The specific requirements for samples and laboratory studies naturally will depend on the state of knowledge about a prospect. Thus, it may be advisable to perform extensive sampling and a complete suite of laboratory measurements on a wildcat well when nothing is previously known about the reservoir; this may provide the only fluid data on which to base future exploration work. However, the early wells in a field may not provide the best samples because drilling and workover practices will not have been optimized, and the wells’ response to testing programs may require changes that are detrimental to fluid sampling. 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.
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. It is thus difficult to obtain a representative sample of a given subsurface body of water. Any one sample is a very small part of the total mass, which may vary widely in composition. 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. There is a tendency for some oilfield waters to become more diluted as the oil reservoir is produced. Such dilution may result from the movement of water from adjacent compacting clay beds into the petroleum reservoir as pressure declines with the continued removal of oil and brine. The composition of oilfield water varies with the position within the geologic structure from which it is obtained. In some cases, the salinity will increase up-structure to a maximum at the point of oil/water contact.
Determining measurements required
The first priority in developing a sampling program, whether extensive or limited, is to establish exactly what measurements are required. Table 4.1 gives a wide range of the measurements that are typically considered for exploration wells. This can be used as a checklist, together with direct contacts with users in other functions, to identify specific requirements for sampling and on-site measurements. 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. Table 4.1 is not a comprehensive list, and other measurements will be required in certain locations and for specific purposes.
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. The program should specify who has overall responsibility if a change is required in the program, as often occurs. Sampling programs should not be developed in isolation from the other objectives of a well test because there is direct conflict in some cases, such as when the well test requires large drawdowns for gas/condensate fluids as part of flow-capacity tests. 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. In the case of fluid sampling and on-site analyses, the following sorts of questions should be considered in deciding the detailed sampling objectives: #How much information is available on the likely reservoir fluid?
- What types of fluid sampling will be best?
- What is the most suitable well-cleanup and -conditioning procedure, and how can this be integrated with other well-test objectives?
- How many samples are needed, and do partners need duplicates?
- When is the ideal time to take samples?
- Will on-site analyses be required?
- Who will perform sampling and analysis duties?
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, it is recommended either to use specialist laboratory personnel or to supervise the service-company operations closely. See preparing for fluid sampling for additional information.
General guidelines for choosing reservoir-fluid-sampling methods and sample quantities required are summarized in Table 4.2. Regardless of the actual volumes mentioned, you should collect at least two separate samples of each fluid, referred to as duplicate or replicate samples. This reduces the chance of losing information if one of the samples leaks or is accidentally damaged during laboratory operations, and it allows a comparison between the samples as part of the quality-control procedures.
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. If the test has to be aborted for some reason [well bridging, unexpected levels of hydrogen sulfide (H2S), etc.], the backup samples may be of great value, even if they are not 100% representative. If the test is completed successfully, the backup samples can be discarded to avoid the cost of unnecessary shipment and testing.
If sampling is part of a long-term monitoring program, such as those required by government authorities or those forming part of custody-transfer contracts, the methods defined in the appropriate documentation or contracts must be followed as closely as possible, even if this constitutes differences with the procedures or recommendations in this text or in the industry standards cited here. Full use of this text and appropriate industry standards should, of course, be made in setting up new procedures and contracts that require long-term sampling and measurement programs.
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.
In some cases, fluid sampling may be made on short notice in response to a problem, with the intention of identifying the cause and preventing any recurrence. Here, it is essential to record all the operating conditions and any changes that may have contributed to the problem. Also, it can be useful to collect a reference sample when operation is normal, if this is possible (e.g., a sporadic problem or a similar installation not affected), to allow comparisons. Laboratory personnel also should be contacted regarding the sample needs and the types of analyses that could be performed.
Sampling procedures differ based on whether the fluids are pressurized or not. For applicable procedures, see
- Downhole fluid sampling
- Surface sampling of reservoir fluids
- Nonpressurized hydrocarbon fluid sampling
- Oilfield water sampling
- Measurements affecting reservoir fluid sampling
- Quality control during reservoir fluid sampling
- Fluid sampling safety hazards
Special topics and considerations in fluid sampling
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.
As for all sampling activities, every effort should be made to obtain representative samples. When sampling from pressurized lines and vessels, care should be taken to ensure that emulsification does not occur during the sampling process itself. For example, samples obtained at the wellhead or production headers may show a high percentage of emulsion (as a consequence of the sampling as the sample was depressurized into the sample container), whereas the actual oil and water inside the piping may or may not be in the form of an emulsion. 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 Fig. 2 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.
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. Emulsions are covered in more detail elsewhere in this Handbook.
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.
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.
Sample bottles containing movable mixing devices are recommended in all these cases, as returning samples to original sampling conditions and agitating for a lengthy period (e.g., overnight) gives the highest chance of recovering representative samples from samplers or sampling cylinders.
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. 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.
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: (1) high nitrogen or helium is anticipated, (2) early decisions must be made on the basis of gas sales value, (3) variable nonhydrocarbon concentrations occur within a field and will contribute to property mapping or be used to determine if fluid sampling is required, or (4) sample transport logistics mean that laboratory analyses may take a very long time.
The possibility of sulfate-reducing bacteria (SRB) contaminating completion fluids and even souring the reservoir itself represents a significant risk, and tests on site or sampling for SRB are recommended to identify and address potential problems. Tests that give a negative result can be particularly helpful in identifying the origin of SRB development later in the life of a field.
Many additional analytical measurements can now be performed on site because there is a wide variety of portable chemical test kits available, especially for water analysis. However, suitably trained operators are essential.
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.
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.
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
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.
Among the major developments in the past 10 to 15 years is the progress toward the worldwide elimination of the use of mercury in fluid-sampling operations, producing significant improvements in personnel safety and environmental protection. Efforts must continue to achieve better management of sampling programs and cost-efficient sample storage, despite the difficult challenge of trying to assign monetary values to fluid samples and the measurements made on them.
Specific technical developments that can be anticipated are a greater use of automatic surface-sampling systems, introduction of equipment better designed to preserve reactive samples such as fluids containing H2S, an increase in gas/condensate downhole sampling and in use of downhole sampler technology (such as heated chambers for sampling waxy fluids), and downhole measurement of simplified composition and physical properties such as bubblepoint.
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.
- 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
- ASTM D4888-88(1999) Standard Test Method for Water Vapor in Natural Gas Using Length-of-Stain Detector Tubes. 1999. West Conshohocken, Pennsylvania: ASTM International. http://dx.doi.org/10.1520/D4888-88R99
- Williams, J.M. 2003. Getting Reliable On-Site H2S and CO2 Concentrations for Anti-Corrosion Measures in Gas Wells. Presented at the Middle East Oil Show, Bahrain, 9-12 June. SPE-81495-MS. http://dx.doi.org/10.2118/81495-MS
- Roberts, G.L., Kelessidis, V.C., and Williams, J.M. 1991. New System Provides Continuous Quantitative Analysis of Gas Concentration in the Mud During Drilling. SPE Drill Eng 6 (3): 219-224. SPE-19562-PA. http://dx.doi.org/10.2118/19562-PA
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