New Solutions inFluid SamplingRepresentative fluid samples are essential for

the exploration and development of oil and gas

reservoirs. High-quality samples enable the asset

team to determine pressure–volume–temperature

(PVT) properties such as density, formation volume

factor, viscosity, interfacial tension, gas/oil ratio

(GOR), or compressibility; generate relative

permeability relationships; or assess enhanced

oil recovery strategies.

In this article, Andrew Carnegie outlines the main

challenges in fluid sampling and reveals how the

latest technology has improved sampling by making

it faster, more accurate, and cost-effective.

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Almost all of the technical andeconomic studies conducted for

exploration and production require a detailed understanding ofreservoir fluids. Fluid samplingprovides critical information for awide range of professionals.Geologists, reservoir engineers,completion and productionengineers, and facilities and flow-assurance engineers all benefit fromaccurate fluid properties.

Geologists use fluid data forreservoir correlations, geochemicalstudies, and hydrocarbon-sourceanalysis. Reservoir engineers needreliable fluid information so that they can estimate reserves, performmaterial-balance calculations, simulatethe reservoir, and interpret well testscorrectly (Figure 1). Completion andproduction engineers use fluids toguide their decisions on completiondesign, material specification,artificial-lift calculations, production-log interpretation, production-facilitiesdesign, and production forecasts.Facilities and flow-assuranceengineers rely on fluid data to manageflow assurance, separation and fluidtreatments, and metering andtransport issues.

The downhole fluid samplingprocess presents engineers with aseries of technical challenges. Theseinclude selecting the correct zone forsampling, connecting to the reservoir,minimizing contamination, obtainingsufficient sample volume for analysis,maintaining samples as single phase,and transporting unaltered samples to surface and laboratory facilities.

In the early days of the oil and gasindustries, sampling was conducted atsurface and little effort was made toestablish fluid conditions at formationdepths. Companies that bought orsold hydrocarbons needed to knowhow much was being transferred, and to do this they had to be able tomeasure the volume and compositionof fluids. Fiscal metering of crude oil and gas has always been a crucialelement in any field operation.

Today, the measurements performedon a fluid sample from a reservoir willusually include PVT relationships,viscosity, composition, GOR, and

differential vaporization, and amultistage separation test. Fluidsamples also provide the informationneeded to help with the planning andthe special treatments that may berequired for production, for example,assessment of waxing tendency andasphaltene content, or the removal ofhydrogen sulfide.

Hydrocarbon composition can varysignificantly within a reservoir, andthese variations must be assessed andrecorded. Compositional properties areimportant in verifying the saturated

hydrocarbon concentrations that relateto wax production. Waxes can causeblockages in subsea pipelines andproduction facilities. Asphaltenes aretar-like solids that can come out ofsuspension in crude oil when thepressure is reduced, and they cancause serious problems in the near-wellbore region, the production tubing,and the surface facilities. The assetteam may also send samples forrefining trials to assess their suitabilityand requirements for downstreamprocessing (Figure 2).

Sampling as an exploration toolDuring exploration, fluid samplinghelps to answer key questions aboutthe reservoir. It indicates how muchhydrocarbon is actually present withinthe structure, reveals reservoircompartmentalization, and helpsreservoir engineers to establish thefluid contacts and any hydrocarboncompositional gradients that mayexist in a compartment. The resultsfrom fluid analyses are key elementsin reservoir modeling and simulationthat will shape field development.Before field development, thereservoir engineer must determinephysical and chemical factors such as viscosity, density, wax, emulsions,asphaltenes, and GOR.

Once the asset team has made itsassessment of reserves, the next step is to define the fluid properties and thecomposition of the hydrocarbons. Whenthe team has established which kinds of hydrocarbons are present, they canpredict potential health, safety, andenvironment (HSE) concerns and planto avoid them. For example, when areservoir contains hydrogen sulfide it is vitally important to establish theconcentration of this toxic andcorrosive substance as soon as possibleand to develop an appropriate profilefor the production facilities.

The economics of any fielddevelopment rely significantly on theprediction of hydrocarbon-recoveryrate. The type of hydrocarbon and the physical conditions within theformation directly influence therecovery factor. Fluid sampling andanalysis help the asset team to forecastrecovery and predict any problemsthat might be encountered in thereservoir, the well, or the surfacefacilities. Fluid information is also ofvital importance further downstream—refinery managers need a clearindication of crude oil composition to ensure efficient processing and toassess the type and the value of therefined products (Figure 3).

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Checking fluids for field developmentField development is an extendedperiod of intense activity and may takemore than a few years to complete.During this phase, development wellsare drilled and surface facilities andgathering systems are built and enterservice. Hydrocarbon productionclimbs toward peak levels and, inmany cases, water or gas injectionstarts to support reservoir pressure.Artificial-lift methods may also beintroduced to assist flow in the well.Throughout this period, the assetteam will have to make importantdecisions about the field.

During the field development phase,fluid sampling may help to boostrecovery (for example, by optimizingwaterflooding schemes) and aid theasset team in designing and building

Figure 1: Planning the next move: accurate information helps engineers to optimize production.

Figure 2: Crude oil is an extremely complex mixture of compounds, and refining processes must bematched to specific compositions.

Figure 3: Analysis of hydrocarbons is required to ensure efficient processing and to predict the typeand the value of the refined products.

the appropriate facilities for the field.In the early stages of development,the operator will need to develop astrategy to meet production targetsand sustain production levels over the course of any supply contract.Sampling helps reservoir andproduction engineers to determinewhich zones require perforation andwhich (for example, those containingheavy fluids such as tar) should be ignored. Once production isestablished in a part of the field, fluidsampling, together with pressuremeasurements, can help to identifybypassed hydrocarbon zones in orderto increase ultimate recovery.

Sampling during production

Photograph, Science Photo Library

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Chemistry and classification ofcrude oilCrude oil is a complex mixture ofhydrocarbons and heteroatomicorganic compounds of varyingmolecular weights and polarities. Thechemical classification of hydrocarbonsdivides these compounds intosaturated and unsaturated types.

Saturated moleculesThe simplest hydrocarbon molecule is methane (CH4), which comprisesone carbon atom and four hydrogenatoms; the next in the series is ethane(C2H6). A whole class of chain-likehydrocarbons (paraffins) can bedefined according to the generalchemical formula CnH2n+2.

Paraffins can be arranged either in straight chains (normal paraffinssuch as butane) or in branchedchains (isoparaffins) (see Figure 4).In naturally occurring crude oils,most of the paraffin compounds arenormal paraffins, while isoparaffinsare more likely to be products fromrefinery processes. Normal paraffinsdo not perform well as motor fuels,but isoparaffins have good engine-combustion characteristics.

For hydrocarbon moleculescontaining more than four carbonatoms, the carbon atoms may form a closed-ring, known as a cyclo-compound, rather than a branched or a straight chain. Saturated cyclo-compounds are called naphthenes.Naphthenic crude oils tend to be poor raw materials for lubricantmanufacture, but are more easilyconverted into high-quality gasolinesthan paraffins.

Given the pattern of moderndemand (which tends to be highest fortransportation fuels such as gasoline),the market price of a crude oilgenerally rises with increasing yield oflight products. It is possible to processheavier crude oils more intensely inorder to improve their yield of lightproducts, but the capital andoperating costs required to supportsuch high-conversion processes aremuch greater than those required toprocess lighter crude oils into thesame yield of products.

In addition to hydrocarbons, smallamounts of sulfur, nitrogen, and oxygencompounds are present in crude oils. Usually, there also are traces ofvanadium, nickel, chlorine, sodium, andarsenic. These elements may affect thesafety of oil-transport systems, thequality of refined products, and theeffectiveness of processing units withina refinery. Minute traces can usually betolerated, but crude oils with largeramounts of these materials must beextensively treated in order to complywith government regulations.

Problem hydrocarbonsAsphaltenes are high-molecular-weight aggregates that occur in solidbitumens. Asphaltenes are verysoluble in carbon tetrachloride andaromatic hydrocarbons, but not inlight paraffinic hydrocarbons such as heptane. They contain very littlehydrogen, and the high viscosity of heavy oils is probably a function of the size and the abundance ofasphaltene molecules.

The precipitation of asphalteneaggregates can cause problems suchas near-wellbore formation pluggingand wettability reversal. Theadsorption of asphaltene aggregates at oil/water interfaces has also beenshown to cause the steric stabilizationof petroleum emulsions. Consequently,the oil industry needs quantitativetools and thermodynamic data topredict asphaltene aggregation andprecipitation as a function of crude oil composition and reservoirtemperature and pressure.

Figure 5: The proportions of products that can be distilled from five different crude oils.

A crude oil classification systemClassification of crude oil must reflectthe type of oil generated by theorganic matter contained in thesource sediment and any alterationthat the original oil may haveundergone as a result of furthermaturation or degradation.

One classification system defines crude oil by the types ofhydrocarbons (paraffins, naphthenes,and aromatics) that it contains:1. Paraffinic crude oils—less than

1 % sulfur, density usually below 0.85 g/cm3

2. Paraffinic–naphthenic crude oils—less than 1 % sulfur

3. Aromatic–intermediate crude oils—more than 1 % sulfur

4. Aromatic–naphthenic crude oils—less than 1 % sulfur and more than 25 % naphthenes

5. Aromatic–asphaltic crude oils—more than 1 % sulfur and less than 25 % naphthenes

6. Asphaltic crude oils.Types 4, 5 and 6 are heavy crude

oils. All six types can be displayed on a triangular diagram with the three principal hydrocarbon series (Figure 6).

Unsaturated moleculesOlefins and aromatic compounds areimportant components of many crudeoils. Both of these chemical families arecomposed of unsaturated molecules.This means that some of the valenceelectrons on the carbon atom are notbonded to separate carbon or hydrogenatoms; instead, two or three electronsmay be taken up by a neighboringcarbon atom to make a double or atriple carbon–carbon bond.

Like saturated compounds,unsaturated compounds can formchain or ring molecules (see Figure 4).Unsaturated chain molecules areknown as olefins. Only small amountsof olefins are found in crude oils, butlarge volumes are produced in refiningprocesses. Olefins are relativelyreactive as chemicals and can bereadily combined to form longer-chaincompounds. The other family ofunsaturated compounds is made up ofring molecules called aromatics. Thesimplest aromatic compound, benzene(C2H6), has double bonds linkingevery other carbon molecule.

The double bonds in the benzenering are very unstable and chemicallyreactive. It is partly for this reasonthat benzene is a popular buildingblock in the petrochemical industry.Unsaturated hydrocarbons generallyhave good combustion characteristics,but their reactivity can lead toinstability in storage and sometimesto environmental emission problems.

The previous description ofhydrocarbons refers to the simplermembers of each family, but crudeoils are actually complex mixtures of very long-chain compounds, someof which have not yet been identified.

Because such complex mixturescannot be readily identified bychemical composition, refinerscustomarily characterize crude oils by the type of hydrocarbon compoundthat is most prevalent in them:paraffins, naphthenes, and aromatics.Some crude oils, such as those in theoriginal Pennsylvanian oil fields,consist mainly of paraffins. Others,such as the heavy Mexican andVenezuelan crude oils, arepredominantly naphthenic and arerich in bitumen (a high-boiling-point,semisolid material that is frequentlymade into asphalt for road surfaces).

The proportions of products thatmay be obtained by distillation of fivetypical crude oils, ranging from heavyVenezuelan Boscan to the light BassStrait oil produced in Australia, areshown in Figure 5.

Refinery processesEach refinery is uniquely designed toprocess specific crude oils into selectedproducts. In order to meet the businessobjectives of the refinery, the processdesigner selects from an array of basicprocessing units. In general, these unitsperform one of three steps:

1. Separating the many types of hydrocarbon present in crude oils into fractions of more closely related properties

2. Chemically converting the separated hydrocarbons into more desirable reaction products

3. Purifying the products to remove unwanted elements and compounds.

Figure 4: Hydrocarbon molecules may be arranged in straight chains (a, b, and c), rings or branched chains (d and e), and may be saturated (a, c, and e)or unsaturated (b and d). Figure 6: Six crude oil types defined by proportion of paraffins, aromatics, and naphthenes.

Figure 7: Changes in temperature and pressure within the reservoir modify key physical parametersand present a range of challenges for reservoir and production engineers.

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Gas and water injection schemes arecommonly used to boost or maintainoil and gas rates in producing fields.Regular fluid sampling can be used to track changes in fluid compositionand fluid contacts, thus helping theasset team to monitor and optimize its secondary recovery strategies(Figure 7).

Fluid sampling also has animportant role to play in maturereservoirs. In oil and gas fields thathave been in production for manyyears, chemical and physicalparameters within the reservoir mayhave changed notably and require newPVT analyses to optimize late-stagefield performance. This is particularlyimportant in saturated reservoirs.

Pressure, temperature, and phasechangesA wide range of chemical and physicalconditions is encountered in oil andgas reservoirs. Each oil and gasaccumulation presents its ownchallenges, and the collection ofaccurate fluid samples is a key step in understanding reservoir processesand overcoming potential problems.Reservoirs are complex systems, and relatively small changes intemperature or pressure can have aprofound effect on fluid compositionand reservoir behavior.

Before a well is drilled in a newreservoir, the fluids within theformation are at the original reservoirpressure. Oil at this pressure isusually saturated with gas; that is, itcontains all the gas in solution that it can hold under those particularpressure and temperature conditions.Any additional gas forms a free gascap above the oil column (Figure 8).

If the overburden pressure on thereservoir fluids is reduced by erosionor up-dip fluid migration, the oil’scapacity for retaining gas in solutionis reduced, and the gas forms asecondary gas cap (Figure 9).(Thisgas cap should not to be confusedwith the secondary gas cap associatedwith production of oil below itsbubblepoint.) If the reverse happens(an oil accumulation saturated with

solution gas is more deeply buried)the gas cap vanishes as the gas goesinto solution. Eventually, the oilbecomes undersaturated with gas.These changes can be represented

Current sampling methodsAsset teams need to select the mostappropriate fluid sampling method forany given situation or stage in fielddevelopment. The choice is influencedby several physical factors: the volumeof sample required for analysis, thetype of reservoir fluid to be sampled,and the degree of reservoir depletion.Other factors to consider includesurface processes; well-completiondesign, cost, and technical feasibility;and probable environmental impact.The team can only devise an effectivesampling strategy once these factorshave been taken into consideration.There are a number of ways to obtainfluid samples.

Bottomhole samplesBottomhole sampling should always be the first choice when reservoir andwell conditions permit. It providesfresh, uncontaminated reservoir fluidwith the highest degree of verticalresolution. When bottomhole samplingis conducted correctly, the fluid is stillsingle phase. This technique providessmall samples (volumes typically rangefrom 0.25 to 4 L) and is essential whenthe team needs very accurate results.

on a phase diagram that indicateswhat will happen to a petroleummixture under various temperatureand pressure conditions.

Wellhead and surface recombinationsamplesWellhead sampling is possible undercertain conditions, specifically incases where the gas saturationpressure is less than the wellheadpressure at wellhead temperature(Figure 10). However, this approachmay be affected by density gradientsthat result from cooling as fluids moveup inside the wellbore.

Surface sampling from the wellhead,the separator, and the stock tank isperformed routinely during most welltests and it is occasionally requiredfrom production process lines.Separator recombination samples areoften the only available representativesamples. In these circumstances,accurate separator flow ratemeasurements and stable separationconditions are critical for the accuratedetermination of reservoir phasebehavior from the recombined fluids.Unfortunately there are errors inherentin surface sampling: poor stability of the separator during sampling;variations in sampling technique;inaccurate flow rate measurements;and problems encountered during the recombination process.

Sampling while testingIn some fields, the operators mayconsider obtaining fluid samples duringtesting operations. This approachappears to offer time savings and costefficiencies, but the sampling resultsobtained through this method are nothigh quality. Sampling while testingincreases the condensate/gas ratio andresults in loss of liquid. It also causescommingling of the various fluids,which makes it impossible to performselective tests. Sampling while testingalso carries an increased HSE risk, andis relatively expensive.

Figure 9: Up-dip oil migration (a) and erosion of overlaying rocks (b) both reduce the pressuresaffecting the hydrocarbon deposits. Pressure drops can lead to significant changes in hydrocarbonphase composition.

Figure 10: In some cases, wellhead samplingmay be possible. However, results from thismethod may be unreliable.

Figure 8: Gas caps usually develop once production starts and reservoir pressure declines.

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Rapid analysis reduces costsTraditional sampling was a relativelyslow process. A company conductedall its fluid analysis work at a centrallaboratory, away from the wellsite.Transporting samples to thelaboratory, delays while high-priorityfluids from other wells or fields weretested, and extended analysis timesmeant that it could take a relativelylong time for the laboratory to sendresults back to the field. Modernbusiness drivers, such as high dayrates for deepwater rigs, haveencouraged companies to devise new techniques that provide a fasterturnaround of fluid analyses.

Operating companies mustunderstand the fluids in theirreservoir before they can devise and optimize their testing programsand completions. In deepwaterenvironments, delays can be costly,but proceeding without the correctinformation could pose serious HSEproblems. Today, Schlumberger canperform accurate fluid analysis at thewellsite and deliver the results in

Deep waterOperations conducted in deep waterpresent a range of special challenges.Tasks usually cost significantly morethan comparable work on shallow-shelf or onshore locations. Rig ratesfor deepwater operations are veryhigh. Logistical requirements aremore demanding, and there isadditional commercial pressure on the sampling team to collect the rightvolume of sample at the first attemptand then to conduct an accurateanalysis in the shortest possible time.

Real-time, downhole analysis usingthe MDT wireline tool is an extremelyeffective way to obtain accurate fluiddata in a very short time frame. TheMDT tool consists of individual modulesthat can be configured to meet almostany testing and sampling need. A high-accuracy, high-resolution quartz gaugewith a fast dynamic response providesformation and hydrostatic pressuremeasurements. Sensors mounted in the flowline provide measurements of formation fluid resistivity andtemperature while fluid flow iscontrolled from the surface.

Heavy oilHeavy crude oils are those with APIgravity of 22 dAPI or below. APIgravity is an arbitrary scale thatexpresses the gravity or density of

team to define the compositionalequations of state that they require foroffshore facilities design calculations.

Hydrogen sulfideSweetening is the process of removinghydrogen sulfide, carbon dioxide, andother impurities from sour gas.Hydrogen sulfide can cause severeproblems at every stage of oil and gas operations, from downhole wellcompletions through productionfacilities and transport system(pipelines, terminals, tankers, etc.) to refining and end use. For oil andgas operators, the major problemswith hydrogen sulfide are■ corrosion, including sudden,

potentially catastrophic plantfailure as a result of sulfide stresscracking (SSC)

■ toxicity to personnel■ unpleasant smells at 10 ppm or less

in air, which can lead to complaintsfrom individuals or businesseslocated close to any plant

■ reduced value for oil and gasproducts. In some cases, theoperator may be unable to sell thegas. Customer limits for hydrogensulfide may be 3 ppm or less, a leveldictated by the need to prevent SSCin pipelines.

■ increased capital expenditure onsweetening processes and/orintroducing SSC-resistant materialsto the production chain (Figure 12)

■ increased operating expenditure on sweetening chemicals, corrosioninhibitors, scale dissolvers, andbiocides.

liquid petroleum products. The higherthe API gravity, the lighter thecompound. Intermediate crude oilsfall in the range 22 to 38 dAPI. Lightcrude oils generally exceed 38 dAPI.The most significant problemsencountered when attempting tosample heavy oil are sanding and theformation of emulsions. Heavy oils are difficult to produce and requirespecial production techniques, suchas steam injection or steam soak, toextract them from the reservoir.

Low-energy reservoirs and lowambient temperatures make therecovery and transport of heavycrude oils complex and demandingissues. Flow assurance during thetransportation of high-viscosity crudeoils is a major challenge for heavy-oildevelopments. Some heavy crude oilshave high total-organic-acid contentsthat can lead to naphthenateprecipitation in offshore processingfacilities and problems duringrefining operations.

Accurate fluid-property data arevital for reservoir modeling andfacilities design. For offshore heavy-oilsystems that are to be produced incolder waters, it may be necessary tomeasure PVT phase-behavior data atthe cooler flowline conditions as wellas at the reservoir conditions. Theselower-temperature data help the asset

around 10 h. The results can be usedto quickly update reservoir modelsand so optimize field developmentstrategies (Figure 11).

Current challenges in sampling The main aim of field sampling is to collect the required volume ofrepresentative fluid quickly andwithout contamination. In general,sampling is difficult in formationswhere the fluids do not flow easily.Low flow rates are encountered inmany reservoir types, including tight, low-pressure, and damagedformations. Hot reservoirs provide adifferent challenge—phase changesare difficult to prevent when the fluidis brought to the lower temperatureand pressure at surface.

There are also reservoirs where well testing is not allowed, and thenthere are those that can give specificproblems with sampling methods, forexample, oil-base mud contaminationin MDT* Modular FormationDynamics Tester sampling of clasticreservoirs or sanding.

OnshoreTight or hot reservoirs present the major challenges for onshoresampling operations. For oil and gas fields located close to built-upareas, there are often operationalrestrictions; for example, well testingmay be prohibited.

In tight formations, the fundamentalchallenge for sampling techniques iscollecting enough fluid from theformation to constitute a representativesample. Tight formations may havegood oil or gas saturation values butlow permeability, which prevents thehydrocarbons from flowing freely intothe wellbore. Stimulation techniquessuch as fracturing may help.

OffshoreThere are also restrictions on testingoperations in the offshore environment.Concerns about wildlife and HSE issuesmean that sampling must be conductedin a way that eliminates discharges andenvironmental contamination withoutcompromising the safe operation of the facility.

When samples are taken offshore,the field operators must either sendthe samples to an onshore facility orperform the analysis on the platform.Offshore, space is often limited, soany analytical equipment deployed onthe platform will have to be compactand easy to maintain.

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Figure 11: High-quality samples and wellsite analysis enable field operators to update their reservoirmodels in a matter of hours.

Figure 12: Gas treatment to remove hydrogen sulfide is a complex process that requires high levelsof capital investment. Accurate fluid samples help field operations to determine if treatment will berequired for a particular crude oil.

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Each of these potential problemscan be avoided if the design stage ofany new field or facility is undertakencorrectly. Operators must obtainrepresentative samples and accurateanalyses of reservoir fluids, aquiferwater, and other fluids such asinjection water.

Correct sampling and analysisrequire very specialized techniques,especially in situations with lowconcentrations of hydrogen sulfide or in the presence of nutrientprecursors (such as carboxylic acids)for the anaerobic bacterialgeneration of hydrogen sulfide.Without specialized techniques,these chemicals may not beaccounted for during analysis. Forexample, bacterial nutrients maydisappear through aerobic bacterialaction in samples that have beenexposed to air, and hydrogen sulfidemay disappear by oxidation reactionwith iron in the well tubulars, oreven the stainless steel in samplebottles. If the facilities design teamfails to identify the risk of hydrogensulfide generation, the resultingproblems could prove very costly.

Reliable prediction and monitoringof changes to field waters and oil and gas phases during field life andproduction and transport operationsare major issues (Figure 13).Operators must be aware of issuessuch as reservoir souring followingwater injection; bacterial generationof hydrogen sulfide in flowlines andtanks; corrosion predictions; theeffects of pressure and temperaturechanges, and exposure in open tanks;and the use of chemicals to controlbacteria or remove hydrogen sulfide.

Carbon dioxideThe carbon dioxide content of a crude oil also has implications for the economic viability of any fielddevelopment project and the assetteam’s plans for facilities design andproduction. Carbon dioxide is verysoluble in oil and gas, and can be usedin miscible tertiary-recovery schemesin depleted oil fields. However, whencarbon dioxide occurs naturally withinthe reservoir it can cause significantproblems for field development.

� establish a new sampling techniquethat would reduce pressure shockto the formation fluid

� conduct fluid-flow modeling studiesthat would lead to improvedsampling techniques, thus shorteningsample time while reducing ultimatecontamination levels

� bring samples to the surface withoutchanging their initial phase (Figure 14).

Accurate fluid samples and precisepressure dataThe introduction of the MDT toolrevolutionized downhole fluid samplingand pressure measurements. This toolwas designed to identify and collecthigh-quality reservoir fluid samples andbring them to surface for detailedlaboratory analysis. Flowline resistivitymeasurements taken using the probemodule helped to discriminate betweenformation fluids and filtrate from water-and oil-base muds. Formation fluid

Figure 13: Downstream facilities perform regular checks on the hydrocarbons arriving from thefield. Hydrocarbons with components such as hydrogen sulfide or carbon dioxide require specialarrangements for transport and treatment.

could be excluded from the samplechamber, using real-time surfacemonitoring, until an uncontaminatedsample was recovered. This saved timeat the wellsite and helped to avoid thecosts of sending low-quality samples foranalysis. For example, in oil-base mudsamples, contamination levels fell toless than 1 % when using the MDT tool.The MDT tool also provided fast andaccurate pressure data, and could beused to measure permeability tensor.For the first time, reservoir engineerscould assess these vital reservoircharacteristics in a single trip and gaina wealth of information about pressure,permeability and fluid PVT propertieson which to base key decisions.

Single-phase samplingAccurate compositional and PVTanalysis of formation samples requiresthe recovered sample to remain atformation conditions. This ofteninvolves maintaining samples in

a single phase. Many samplingchambers work on the principle oftrapping a fixed volume of single-phase fluid at reservoir conditions.However, as the sample is brought tothe surface, the temperature in thechamber decreases. This cooling leads to a pressure drop within thechamber and, in most cases, results in the sample passing through thebubblepoint and becoming agas–liquid mixture. As the pressureapproaches the bubblepoint,asphaltenes and paraffins may be precipitated. Recombiningprecipitated asphaltenes in thesample chamber calls for a longrepressuring process. Unfortunately,some of the changes that may haveoccurred during sample retrieval maynot be fully reversible. Compositionalchanges will also alter other criticalproduction parameters such as GOR,viscosity, and API gravity.

Figure 14: Rapid sample analysis means results that once took weeks can now be obtained in a few hours. This delivers dramatic savings in costlydevelopments such as deepwater fields without compromising safety.

High levels of carbon dioxide areuncommon in the world’s reservoirs.Fewer than 1 in a 100 gasaccumulations will have carbon dioxideconcentrations greater than 20 %.However, where the carbon dioxidecontent of a reservoir exceeds 20 %,the mean concentration is 50 % carbondioxide. In other words, when carbondioxide is abundant, it is frequently soabundant that it can kill the prospect’seconomics. High carbon dioxideconcentrations are encountered inseveral key Asian oil and gas fields,including in the South China Sea, theGulf of Thailand, and Australia.

Fluid-sampling technologyBy the mid-1990s, wireline formation-testing tools were well established inthe industry. But, when it came torecovering reservoir fluids, these toolshad a major limitation: the flow samplesthey collected were often contaminatedwith drilling mud filtrate. Thesecontaminated samples could be used to prove the presence of hydrocarbons

within a specific zone, but wereunsuitable for rigorous PVT analysis.Even when they were uncontaminated,the bottomhole samples often had thewrong bubblepoint or had lost pressureas the sample was being retrieved.Consequently, when operators had bothsurface and bottomhole samples, theyusually relied on the surface sample toprovide the data they were seeking.

However, as the industry started to operate in fields with more andmore complex fluid systems it becameapparent that bottomhole samplingwas vital. Fluid samples, like pressurereadings, are best taken close to thereservoir. By the late 1990s, engineerswere working to improve bottomholesampling and to develop tools thatwould enable fluid analysis to beconducted downhole. Their long-termobjectives were to� develop a downhole fluid analysis

technique that would minimizesample contamination and determinein situ hydrocarbon properties

Photograph, Science Photo Library

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Maintain reservoir conditionsOne solution for maintaining samplesat reservoir conditions involvesoverpressuring the samples once theyhave been collected. To achieve this,sample chambers are pressurizedacross two pistons with a nitrogen gaschamber, thereby compensating forthe temperature-induced pressuredrop as the samples are returned tosurface. The single-phase multisamplechamber (SPMC) is designed for usewith the MDT multisample module(Figure 15). The nitrogen is isolatedfrom the sample chamber and acts onthe sample through a piston floatingon a synthetic oil buffer. Thepressurized gas charge maintainspressure in the sample chamber andensures that the sample remainsabove the bubblepoint line and theasphaltene precipitation threshold(Figure 16).

Single-phase sampling saves time atthe wellsite because there is no needto recombine samples in the field. Inaddition, the SPMC provides a custom-designed transfer system that cantransport samples to the laboratoryquickly and safely. Single-phasesampling has encouraged analysts toexplore new aspects of fluid behaviorand made it easier for them to conductstudies into asphaltene precipitationand deposition, aquifers, andcorrosion.

Condensates and the samplingprocessCondensates are low-density, high-API-gravity, liquid hydrocarbons thatare usually found in association withnatural gas. Gas produced inassociation with condensate is calledwet gas. The gas/liquid distributiondepends on the temperature andpressure conditions in the reservoirand whether these will allow thetransformation from vapor to liquid.

The presence of pressure-sensitivecondensates can complicate productionbecause liquid will condense out of thegas if the reservoir pressure dropsbelow the dewpoint. This is usuallyundesirable and reduces wellproductivity considerably.

Subsurface sampling tools help toensure that fluid is sampled above thedewpoint. The major problem withthese tools is the high probability ofsample contamination. Even a smallamount of contamination can causesignificant errors in PVT analysis.Contamination from oil-base mud isparticularly difficult to detect.

The MDT tool allows fluid to bepumped through it and uses optical-and density-related techniques fordetermining the nature of the fluidcollected (Figure 18). Surfacereadouts of these data should becarefully monitored to try to ensurethat the fluid composition is stable(see Figure 14).

The openhole approachOpenhole sampling does not disturbthe pressure within a formation, sothe engineer can sample saturatedand near-critical fluids withconfidence. The method providesearly PVT data without a well test,which reduces both costs andenvironmental exposure, and makes it easy to evaluate several formationintervals and examine different zonesand even fluid variations with depthwithin a zone. However, withopenhole methods, samples willalways be contaminated to someextent and the volume of fluid thatcan be recovered is limited.

Testing cased wellsWell conditioning before PVTsampling is extremely important.Well clean-up times should becarefully planned to ensure that all contaminants are removed.Hydrocarbon withdrawal must beminimized before sampling, andproduction must be stable beforeand during the sampling process.The sampling team should monitorwellhead pressure and temperature, and may choose to track othercompositional indicators such ascarbon dioxide content and watercomposition. Effective wellconditioning may take days, even in high-permeability reservoirs.

Hydrocarbon columns havecompositional variations with depth,so for ideal subsurface or surface PVTsampling, it is best to have smallperforation intervals. Short intervalsenable the sampling team to capturethe compositional variations. If theperforations are over a large payinterval, the fluid samples willrepresent the most mobile fluid.

Unfortunately, there are oftenconflicts between the requirements forPVT sampling and the requirementsfor productivity testing during a welltest. Productivity testing requires largetubing, high drawdowns, and largeperforation intervals. PVT samplingrequires exactly the opposite.

Figure 15: Pressurization using the SPMCcounteracts temperature-related pressuredrops that occur as fluid samples are broughtto surface.

Figure 16: The phase envelope diagram explains how the nitrogen overpressure andcompressibility enable the SPMC to keep the sample above not just the saturation pressure butalso the reservoir pressure. This is extremely important because many asphaltenes deposit atpressures far in excess of the saturation pressure.

In well interventions, where themain priority is recovering a high-quality sample, single-phase samplersare the most effective tools. They areparticularly useful in situations whereanalysts want to avoid samplerecombination in the field, forexample, when dealing with heavycrude oil or gas condensate.

Low-contamination samplesPVT-quality, single-phase fluidsamples can be used to establish thepresence of producible hydrocarbons.In one field, the test was conducted ina fault block where the formation waspartially consolidated; there had beenmiscible drilling-fluid invasion, andwater saturations were in the range40 to 50 %.

The MDT tool, which was run in conjunction with the SPMC,recovered two low-contaminationsingle-phase samples. Analysis of these enabled the operator toestimate the recoverable reservesaccurately. Moreover, single-phasePVT analysis revealed the criticalparameters for optimal completionand production design. All of this was achieved without the additionalexpense, delay, and environmentalissues of drillstem tests.

Laboratory-based analysisThe traditional approach to fluidanalysis involves transferring allsamples to a central laboratory for any analytical work. Onsite analysis has improved significantly over recentyears, but some tests still have to beconducted in a laboratory environment.To ensure quality and accuracy,operators require an integrated processthat covers the provision of suitableuncontaminated sample transferbottles, tracking of the samples, andtheir delivery to the central facility.

Reservoir fluid sampling and flow-assurance studies

Laboratory PVT tests provide the data necessary to assess the flow-assurance risk. Laboratory testingdefines the phase behavior andphysical properties of the waxes,asphaltenes, and hydrates that are the principal causes of flow problems.Flow assurance is a multidisciplinaryprocess that involves sampling,laboratory analysis, production, andfacilities engineering working togetherto ensure uninterrupted optimumproductivity. To meet this challenge,Schlumberger uses a dedicated flow-assurance team. This team combinesproducts, services, and technologiesfrom the Schlumberger businessgroups to provide fully integratedsolutions that help operators tominimize costs and meet theirproduction objectives.

The best laboratories usually have afull range of PVT facilities and set-upsto characterize fluid samples, bothvisually and quantitatively, at realisticthermophysical conditions. Forexample, the Oilphase-DBR* fluidsampling and analysis services providecomprehensive flow-assurance studiesthat help to prevent or reduce the flowimpairment caused by deposition oforganic solids. The Schlumberger PVTExpert* system processes all laboratorymeasurements and instantly providesthe final PVT report (Figure 17).

Figure 18: The MDT tool can determine thenature of the fluid collected and ensure thatevery sample is free of contaminant.

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Wellsite analysisThe time between exploration orappraisal drilling and the manufactureof production process plant isdecreasing. Oil companies areworking towards rapid developmentand early exploitation of their assets.However, before operators can selectmaterials for plant completion andprocess design, they require acomplete understanding of reservoirfluid composition and phase behavior.For example, trace concentrations ofchemicals such as hydrogen sulfideand mercury are difficult to detectand, if overlooked at the time ofprocess design, can have a profoundimpact on cost during production.

Operators can save time and ensureearly warning of problem chemicalsby using a comprehensive wellsiteanalytical service that provides qualitysamples and fluid characterization.This should also include trace-element analysis and monitoring forpotential environmental hazards.Oilphase-DBR services can includewellsite tests to provide PVTestimates and levels of oil-base mudcontamination, and analysis of theamount of hydrogen sulfide in liquidsand gases, and of radon and mercuryin gases and water.

Mercury levels are assessed usingan atomic fluorescence technique.Atomic fluorescence spectroscopy(AFS) is the optical emission fromgas-phase atoms that have beenexcited to higher energy levels byabsorption of electromagneticradiation. The main advantage offluorescence detection compared with absorption measurements is the greater sensitivity that can beachieved because the fluorescencesignal has a very low background. Theresonant excitation provides selectiveexcitation of the sample to avoidinterference. AFS can be used tomake quantitative measurements.Analytical applications include flameand plasma diagnostics, and enhancedsensitivity in atomic analysis.

The PVT Express* serviceAs the pace of field developmentincreases, operators want toaccelerate the analytical processes sothat the results that guide theirdecisions are available within hours.The PVT Express onsite well fluidanalysis service can deliver

comprehensive fluid analysis data for black oil or condensate samples(Figure 19) without HSE risks. Thisenables operators to make rapid andinformed decisions about the need foradditional wireline formation ordrillstem testing.

The PVT Express system offersmany advantages over traditional PVTequipment and services. Mercury-freetechnology eliminates the risksassociated with the use andtransportation of mercury. And the tool has a modular, rugged constructionthat facilitates transportation to anylocation, including the wellsite; thismeans that accurate results can bedelivered in hours rather than in weeksor months.

The PVT Express service usesmeasurement techniques based onproven PVT laboratory proceduresand delivers results that match thosefrom the laboratory (Figure 20). ThePVT Express requires a very smallvolume of sample (less than 50 cm3)to conduct a full PVT study. Itincludes a fiber-optic sensor tomeasure the saturation pressure ofgas condensates, and volatile andblack oils. A helium ionizationdetector is used in dual gaschromatograph to perform C12+ gasand C36+ liquid analyses. The PVTExpress service also providesaccurate testing methods for oil-basemud contamination in samples thathave been collected for wirelineformation tests.

Analysis at the wellsite reduces theamount of testing and saves money. Itmeans that reservoir and productionengineers can have PVT results within10 h and that operators can makeinformed decisions during logging andwell-testing operations.

Optimizing samples in OmanIn Oman, an operator wanted tocollect representative gas-condensatebottomhole samples during a well testand to monitor surface gas and liquidcomposition to achieve stabilized flow.The first set of samples analyzed inthe PVT Express onsite laboratoryhad a measured dewpoint pressureclose to the flowing bottomholepressure, which indicated that thesamples were unrepresentative.

Consequently, the well was producedon a lower choke, and a second set ofbottomhole samples was collected. Thedewpoint measured on this set waswell below the flowing bottomholepressure. This indicated that the wellwas producing monophasically into the wellbore and that the bottomholesamples being recovered wererepresentative. Two gas condensateconstant-volume-depletion PVT studiesand 15 surface sample compositionalstudies were completed at the wellsiteusing the PVT Express system. Thisefficient and accurate samplingprocedure enabled the field operator toplan the next stage of production withgreater confidence.

Figure 17 Analytical flow diagram for the PVT Express service. The report combines measurementsand test results from a number of sources to present a comprehensive picture of key fluid properties.

Figure 19: Comparison of PVT Express data with laboratory results for black oil characteristics (top)and for gas condensate characteristics (bottom).

Figure 20: PVT Express-predicted formulation volume factor (FVF) compared with laboratory results (top)and comparison of PVT-predicted oil viscosities and laboratory results (bottom).

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Typical sample history

LocateThe first challenge in successful fluidsampling is to choose an appropriatelocation along the sandface of the well.The selection process must take intoaccount factors such as the geologicalsequence and structure, so that thesampling tool avoids tight zones orfaulted areas within the formation.Having selected the best location, thereservoir engineer must ensure thatthe sample chamber reaches this spot.

PositionWhen a sampling device is collectingfluids, it should be sealed from thewellbore and have full and continuouscontact with the formation. Thishelps to reduce sampling time andminimize contamination fromwellbore fluids. Schlumberger hasdeveloped a range of techniques toestablish and maintain good contactwith the borehole wall. For example,the MDT tool has a retractable,hydraulically operated probe,embedded in a circular rubberpacket, that is forced through themudcake to make a seal with theformation. Two opposing backuppistons on the opposite side of thetool help to push the probe againstthe formation and thus maintain agood seal.

Minimize contaminationThe next challenge is to collect the sample with little or nocontamination. The basic MDT probemodule contains a variable-rate andvolume pretest chamber; a flowlinefluid resistivity measurement sensor;a temperature sensor; and twopressure gauges, including a fast,high-precision CQG* Crystal QuartzGauge instrument that enablessensitive monitoring of drawdownpressures during the samplingprocess. Sample fluids andcontamination levels are monitored inthe flowline by the OFA or the CFA*Composition Fluid Analyzer module.

RetrieveThe sample chamber must berecovered to the surface with theminimum disturbance to the phasecomposition of the fluid. The natural

Spectroscopic analysisSpectroscopy is a well-establishedanalytical technique that cancharacterize complex mixtures. Itrelies on observing how different typesof molecule behave when exposed toelectromagnetic (EM) radiation. Everymolecular structure interacts with EM radiation in a different way. These differences are invaluable inidentifying the structures and theproportions of the molecular typespresent in a sample, and sodetermining the sample composition.

The data obtained fromspectroscopic analysis are presentedas spectra; plots of the levels ofabsorption (optical density†) versusthe wavelength (or mass, momentum, or frequency, etc.) of the energy.Spectra can be used to identify thecomponents of a sample (qualitativeanalysis) or to measure the amount of a specific material in a sample(quantitative analysis).

Infrared (IR) spectroscopyAbsorption of IR radiation can causethe various bonds within a molecule to vibrate differently, as they absorbthe radiation at differing frequencieswithin the infrared region. Thisfrequency depends on the type ofbond (its strength) and the atomsinvolved (their masses). Bonds of the same type (for example, anoxygen–hydrogen bond) tend toabsorb at around the same frequency,even if they are in different molecules.

Nuclear magnetic resonance (NMR)spectroscopyNuclear magnetic resonancespectroscopy relies on the absorptionand emission of radio-frequencyradiation by the nuclei of certainatoms when they are placed in amagnetic field, and can be used todetermine both the structure andrelative amounts of the analyzedsamples (Figure 21).

Optical properties of wellbore fluidsLight passing through a fluid sample is affected by two distinctprocesses—scattering andabsorption. The absorption spectrumof crude oil exhibits a series ofabsorption peaks with diminishingintensity at shorter wavelengths(Figure 22). These peaks indicate the presence of various fluid types.

The largest oil peak that can be seenusing the OFA* Optical Fluid Analyzerspectrometer is at 1,725 nm. This peakcorresponds to molecular vibrationsthat involve hydrogen–carbon bonds.

Such vibrational peaks, which arelocated at discrete wavelengths, orenergies, are analogous to the resonantfrequencies exhibited by mechanicalsprings or tuning forks. As thehydrogen–carbon chemical groups ofall oils and asphaltenes are similar,these vibrational peaks are comparablefor most oils. Materials that are black,such as tar, absorb the entire spectrumof visible light through many differentmolecular vibrational and electronicexcitations. In these cases, theabsorbed energy is converted into heat.Water exhibits strong vibrationalabsorption peaks observed in thespectrometer at 1,445 and 1,930 nm.

Figure 22: The key components of oilfield samples. Spectroscopic analysis can be used to identifysample composition.

reduction in temperature andpressure, and the accompanyingphase changes can be counteractedby increasing pressure within thechamber before retrieval.

AnalyzeThere are now several options forsample analysis. Advanced studies arestill conducted in a central laboratory,but, over the past few years, wellsitesystems have accelerated theanalytical process and enabled theprovision of answers in hours ratherthan in days or weeks. Since 2002,there has been the option to use theCFA analyzer to perform detailedanalysis in the wellbore. This modulerepresents a significant newopportunity, as it can performsophisticated analysis andcharacterization of reservoir fluidswithout having to bring samples tothe surface.

Downhole fluid characterization

Schlumberger introduced downholefluid analysis in 2002. This representeda major advance on previous analyticalsystems and enabled reservoirengineers to obtain accurate, reliablemeasurements of reservoir fluids atreservoir conditions. The development

of downhole techniques has come in response to oil industry demands for rapid, detailed compositionalinformation and greater reliability in sample selection.

At present, the informationavailable from downhole techniquesincludes GOR, composition, APIgravity, pH, water cut, saturationpressure, and contamination levels.

Fluid composition from opticalabsorption spectrometry data The CFA module contains an opticalabsorption spectrometer that usesvisible and near-IR light to quantify afluid’s composition as it flows throughthe tool (Figure 23). Light istransmitted through the fluid to anarray of detectors tuned to selectedwavelengths. The amount of lightabsorbed by the fluid depends on its composition. The measuredabsorption spectrum is represented as a linear combination of the uniqueabsorption spectra for C1, C2–C5,C6+, carbon dioxide, and water, andenables determination of the weightpercent of each molecular group.

In gas reservoirs, oil vaporized in the gas will precipitate as liquidcondensate at surface temperatureand pressure conditions. The CFA

Figure 23: An optical absorption spectrometer in the CFA module quantifies fluid composition as itpasses through the tool.

Figure 21: NMR spectroscopy helps scientists to determine molecular structures in complex hydrocarbons.

†Optical density is log10(I0/I1), where I0 is input light

energy and I1 is transmitted light energy.

Photograph, Science Photo Library

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Reservoir architecture and fluid changes Even using logs and seismic data, itcan be difficult to determine whichlayers are connected in layered gasreservoirs. An accurate determinationof connectivity is fundamentallyimportant to reservoir developmentplanning (Figure 25). Thecommingling of gases of differentcomposition can be very undesirable—particularly if some gases haveunacceptably high percentages ofcarbon dioxide. Gas samples can beacquired and analyzed at the surfacein a relatively brief time frame if thereare not many layers. If a multilayeredwell needs to be cased and perforatedin a matter of days, then using theCFA tool to measure gas compositioncan be a fast and accurate solution.

The CFA module can be used tomonitor gas-injection patterns insecondary recovery developmentprojects (Figure 26). In a gas-injectedfield in the Middle East, the operatorhad trouble modeling and monitoringthe injection in the layers beingproduced. The solution involvedrunning a CFA module to track gasinjection in real time.

LFA* Live Fluid AnalyzerThe introduction of the LFA modulehas greatly increased samplingefficiency, as it analyzes fluids as theyflow through the MDT tool. Theanalyzer detects and measuresdissolved methane in live fluids, which are pressurized reservoir fluidsamples that remain in single phase.Engineers can identify downholefluids and make informed decisions onsample acquisition. This has increasedand optimized sampling efficiency,thus saving valuable rig time. Tool

operators can discriminate betweenreservoir hydrocarbons and monitoroil-base-mud filtrate contaminationwhile sampling.

Real-time, quantitativecontamination monitoring is achievedby tracking sample color and methanecontent. The LFA module alsoprovides a predictable cleanup periodfor quality sample collection andreliable discrimination between water,oil, and gas. Free gas is identifiedusing two independent detectors.

Figure 25: The CFA module shows that these reservoir layers, just 5 m apart, are unconnected.

Figure 26: The CFA module helped geoscientists analyze injected gas sweep at four depths. Inthis case, the tool proved that there was no communication between zones A and B.

module measures the composition ofthe condensate while it is still in thegas phase. This vaporized compositionis the C6+ fraction. From the ratio of the C6+ fraction to the C1–C5fraction, the condensate/gas ratio(CGR) is determined. The CGRindicates the condensate yield atstandard temperature and pressureconditions.

The CFA module ensures thatreservoir engineers can obtainrepresentative fluid samples that have acceptably low levels ofcontamination and also minimizes thetime required for sample acquisition(Figure 24). It also enables earlydetermination of GOR or CGR forreservoir valuation purposes.

Sampling gas above its dewpoint The CFA module measuresfluorescence emission using a narrow-spectrum light source, a blue-light-emitting diode. The fluorescenceemission spectrum varies with theamount of condensate vaporized inthe gas; the spectrum changeswhenever the pressure of acondensate falls below its dewpointpressure. Fluid sampling engineerscan, therefore, monitor the spectrumto ensure that the reservoir fluid issampled above its dewpoint.

Depth-related variation in fluidcomposition

Fluid scanning is the evaluation ofreservoir fluids in a large number of zones using a combination ofdownhole analysis and the shortpumpout period available with theMDT sampling string. No fluidsampling is required. In a thick gasreservoir, CFA fluid scanning can beused to measure the compositionalgradient of the reservoir fluid. TheCFA module can provide production-optimizing information such as fluidscanning for a compositional gradientin a thick reservoir; identification oflayers with different fluids; downholeevaluation of carbon dioxide levels;downhole determination of dewpoint;secondary recovery monitoring; andoil-base mud sampling. All of thesedata can be fed back into thereservoir simulation model and sohelp to optimize production.

Figure 24: In this example, the CFA data indicate a drop in contamination over time. Representativesamples can be taken after just 7 minutes.