FLUID SAMPLINGFluid sampling is the techniques to collect sample of fluid by different techniques from subsurface or from surface to check PVT properties of fluid.Importance: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 salesvalue Refinery maintainancecosts Reservoir asset values in generalFluid 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 formationReservoir fluid sampling and fluid properties measurement is a very difficult technique , which has different errors like instrument error, human error 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.Sampling activities in cased-hole wells, 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.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.Although the shape of the phase diagram is specific to the actual fluid composition, it is the reservoir temperature compared to the temperatureTcof the critical point (Tcdetermines if the fluid is an oil or a gas). When the reservoir temperature is lower thanTc, 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 aboveTc, 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 cricondenthermTt, 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).Types of sampling: Surface Sampling Subsurface Sampling

Surface Sampling:Sampling at surface conditions allows for exact control of sample taking from surface and does not put any restrictions on sample volumes. If the same gas/oil ratio (GOR) value is obtained during several or all flow rates, one has a strong indicator for representative samples. Separator sampling is the best method for a reservoir fluid close to or at the saturation pressure (either bubble point or dew point). A special case exists where there is a gas/oil contact in the reservoir. Perforations across the contact will give samples at the surface that can be recombined based on the pressure in the contact and not in agreement with the measured GOR .When sampling downstream of the choke manifold, the well fluid has been subjected to severe conditional changes. The Joule Thompson effect (cooling due to pressure changes) at the choke manifold can result in a large volume of liquid drop out. This can be followed by considerable heating in a heat exchanger. These excessive changes in conditions are not conducive to obtaining good equilibrium and representative fluid samples. In the test separator, there is also a temperature and pressure change that will influence the equilibrium composition of the gas and liquid phases. Heat exchangers can be used to prevent hydrate formation when flowing gas condensates to surface. If inhibitors need to be used, glycol is often preferred to methanol as it has less effect on the measurement of fluid properties. The validity of recombined separator products is dependant upon separator design and efficiency, flow-rate measurement, and sampling technique. Low liquid flow rates are difficult to measure and often result in a reduced GOR accuracy. Tank measurements may be more accurate than meter readings in the case of low flow rates.

Subsurface Sampling:

Also known as downhole sampling.The most important success factor for obtaining representative reservoir fluid samples is to maintain the fluid in single phase during sampling and transfer. This can be accomplished by accurately controlling the sample drawdown pressure and keeping it above the saturation pressure and as close to the reservoir conditions as possible, eliminating the need for a lengthy and sometimes flawed transfer process on surface.For some fluids, the saturation pressure increases with decreasing temperature and therefore, nonrepresentative fluid samples would be collected.Clean up of the sampled fluid is essential to remove soluble contaminants such as oil-based mud (OBM) filtrate and hydrate inhibitors. When the reservoir is saturated, or if the pressure is close to the saturation pressure, obtaining representative single-phase bottomhole samples is difficult if not impossible. Any production with its associated drawdown will cause the producing reservoir pressure to drop below the fluids saturation pressure yielding two-phase flow. During short flow periods (such as bottomhole sampling), some liquid may remain in the reservoir, resulting in unrepresentative fluid samples. A similar problem can occur when transferring the bottomhole samples at surface for transportation to a laboratory for analysis. Small amounts of non-solubilized gas or liquid can potentially adhere to the sample chamber walls (wall wetting) and will significantly affect the volumetric properties (and measured saturation pressure). Infrared, capacitive, and density sensors can be installed in the transfer line to verify if the sample is insingle phase. These sensors may also give an indication of the liquid fraction in a gas sample.

Other Fluid Sampling Techniques:

Nonpressurized hydrocarbon fluid samplingSampling of reservoir fluidsis key to understanding a reservoir and planning surface and subsurface equipment and facilities. While many samples are collecteddownholeor at thesurfacewhile the fluids are still pressurized,may also be gained from samples collected at atmospheric pressure (nonpressurized).Its depend on us wheter we want to collect it in reservoir or at surface by using different equipments. Atmospheric hydrocarbon samples also may be collected from pressurized lines or from samples collected in pressurized chambers, such as downhole samples. Usually, this will involve the release of gas and the collection of oil or condensate. Because the separation procedure that releases gas is dependent on the temperature and pressure (which may be above atmospheric if the liquid is collected in a closed trap), the properties of samples collected in this way may vary. Also, because the fluid in a sample chamber may already be in two-phase condition, liquid from the entire sample should be collected to minimize uncertainty in the sample quality.Sampling from tanks is complicated by the need to collect samples from various depths to allow for any property changes or segregation that may exist.

Oilfield water samplingOilfield watersare often referred to as brines, especially when they contain significant quantities of dissolved salts. They also frequently contain dissolved gases and may contain small quantities of the heavier hydrocarbons found in oils. Water can be present in a surface separator during production, either from liquid waterin the zone being tested or by condensation from water vapor in the produced gas, or possibly from both. Water from aquifers or seawater may also need to be analyzed in connection with water-injection activities.The analysis of oilfield waters has a wide range of applications, including identifying the origin of produced water, characterizing aquifer properties, interpreting wireline-log measurements, predicting formation damage from water incompatibility, investigating scaling tendencies in surface and downhole equipment, monitoring fluid movement in reservoirs, identifying the presence of bacteria, evaluating disposal options and environmental compliance, and predicting and monitoring corrosion.If samples are to be collected for the measurement of trace components, biological species, or reactive chemicals that are likely to be affected by storage, container material, or ambient conditions, on-site analyses should be considered. API RP45lists the following measurements that should be carried out immediately in the field after sampling and filtering oilfield waters: pH Temperature Alkalinity Dissolved Oxygen CO2 H2S Total and soluble iron Turbidity on an unfiltered sample Total suspended solids and washing performed in the fieldSurface sampling is commonly used to obtain a sample of formation water from a sampling valve at the wellhead or another sampling point. A plastic or rubber tube can be used to transfer the sample from the sample valve into the container.Companies Offer Fluid Sampling Services:BakerHughes, Halliburton, Schlumberger, SGS, Pall Corporation, Datacan, DOW Chemical company.