Gas samplingDownhole SamplingRecover formation fluid samples at reservoir conditions with a suite of pressure-compensating equipment that allows controlled, uncontaminated sampling without flashing.Surface SamplingDetermine the amount of liquid carryover in the separator gas line when conditions are stable and separation efficiency is poor.Fluid Laboratory ServicesOptimize production decisions with representative fluid-property measurements and expert-led data interpretation. All services include the highest levels of QA, from the critical first step of sample preparation to advanced studies on PVT, EOR, flow assurance, and heavy oil. Our ability to create real-world reservoir conditionsup to 250 degC and 25,000 psi pressureenables us to handle difficult problems and custom programs that are often beyond the scope of other labs.Wellsite Fluid AnalysisGet PVT onsite well fluid analysis service results in as little as 8 hours. We create a full-fluid properties analysis by combining measurements of the fluid's fundamental properties and predicting the next suite of properties using an artificial neural network.

Wireline pressure testers and reservoir fluid sampling tools have, for quite some time now, been considered viable alternatives to well testing. These tools are widely used to identify reservoir fluids and obtain representative samples for laboratory analyses. In order to recover uncontaminated samples, fluid is first pumped out of the formation into the wellbore, until real-time downhole monitoring of the fluid in the tool flowline ensures it is clean. The reservoir fluid is then captured in sampling bottles or chambers.Firstly, a well-kick and under-balance drilling simulator was used to calculate how much gas could be safely pumped into the wellbore. This, coupled with continuous downhole monitoring of well hydrostatic pressure, addressed well control concerns.In the Wireline toolstring that was used for the operation, 450 c.c. sample bottles were used for collecting the fluid. These bottles were positioned on the top end of the toolstring and the pump module was at the bottom. The basic principle used was that after cleaning up, the pump was stopped for a couple of minutes allowing the fluid to be stationary in the tool flowline, thereby letting any contaminants present in the fluid to settle down. The pump was then restarted, to slowly push the clean fluid column into a sampling bottle. Downhole Fluid Analysis (DFA*) was used to constantly monitor the flowline. The fluid analyzer was positioned in between the pump and the bottle, and as soon as it detected traces of contaminants, the sampling bottle was shut off immediately, even if it was not completely full. For this set-up to work, the volume of flowline between the pump and the bottle had to be enough to fill at least one bottle. This was achieved by adding extra sample chambers in the string, which served the dual purpose of increasing the length of the flowline and taking additional big volume fluid samples. The fluid analyzer also served as a warning device to indicate if there was any undesirable gas-liquid segregation in the tool flowline, upstream of the sampling bottles. Determination of the drawdown threshold and controlling the pumping rate ensured that liquid drop-out did not occur in the flowline, during the critical phase of the operation.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 generalThe 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.[1]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 formationTGeneral guidelines for a sampling programSelecting sampling sitesThe 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 requiredThe first priority in developing a sampling program, whether extensive or limited, is to establish exactly what measurements are required.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.Sampling overviewSurface-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 proceduresSampling 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 samplingAdditional considerations Measurements affecting reservoir fluid sampling Quality control during reservoir fluid sampling Obtaining representative reservoir fluid samples has become of increasing importance in the development and exploitation of oil and gas condensate reservoirs. This is especially true of reservoirs where extensive computer simulations are used to scope out developmental strategies or where enhanced oil recovery options are investigate. Representative fluid samples can usually be obtained from producing reservoirs at surface conditions. Surface samples are removed at either the separator or at the wellhead, with the associated gas and liquid subsequently recombined in proportions to represent the actual reservoir fluid.