Pvt Best Practices

PVT Sampling

Constant Composition Expansion

Density GAS

ConstantConstant Volume Volume Depletion Depletion

OIL Differential Vaporization

ViscosityViscosity

Rino

Casella di testo

PVT BEST PRACTICES

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INTRODUCTION

This Manual was prepared to provide suitable guidelines to deal with PVT activities in order toobtain the best results in each situation.

The experience of our technicians involved in PVT studies was used with the finalgoal to offer a user friendly Manual to any Department or Subsidiary which has to deal with thestudies of reservoir fluids or any other related activity.

In order to achieve this purpose the Manual was designed in six independent sections.Each one of these sections is concerning with a specific subject, mainly investigated from apractical point of view for supporting our colleagues during their daily activities.

The Manual has been succesfully used as a tool for the training as well.

We ‘ ll be pleased to any one who will send us his suggestion or comments which will be used toimprove and keep updated future versions of this Manual.

G. P.

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PVT BEST PRACTICE

CONTENTS Pg.

1. QUALITY OF THE LABS 3

1.1. General information 4

2. RESERVOIR FLUIDS SAMPLING 5

2.1 Aim 62.2 Well conditioning 72.3 Method 82.4 When and how much to sample 102.5 Documents 112.6 Sampling containers 132.7 Field controls 142.8 Suggestions 15

3. CONTROLLING THE VALIDITY OF SAMPLES 16

3.1 General information 17

4. CHEMICAL COMPOSITION OF RESERVOIR FLUIDS 18

4.1 Pressurised liquids 194.2 H2S in pressurised liquid samples 204.3 Pressurised gas 214.4 H2S in pressurised gas samples 224.5 CO2 in pressurised gas samples 234.6 Stock-tank liquids 24

5. PRELIMINARY TESTS AND RECOMBINATIONS 29

5.1 General information 30

6. REQUESTING A PVT STUDY 31

6.1 Reservoir fluid: DRY GAS 326.2 Reservoir fluid: OIL 366.3 Reservoir fluid: VOLATILE OIL 486.4 Reservoir fluid: CONDENSATE GAS 55

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1. QUALITY OF THE LABS

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1.1 GENERAL INFORMATION

The study of reservoir fluids provides the reservoir engineer with fundamentally important data. Forthis reason these studies must be handled by qualified PVT labs, which are able to ensure highquality results.

The use of established analytical procedures, as well as reliable techniques for data evaluation andprecision control methods for measurements taken based on accurate calibration of equipment,are all requisites for this level of quality.

Some labs have quality certification issued by authorized organizations and boards.

A PVT lab must be fitted out with equipment of different types and sizes, suitable for the widestrange possible of temperatures and operating pressures.Usually, each item of equipment is purposely designed and developed to provide an optimalperformance for specific types of reservoir fluids and for particular kinds of experimental surveys.

Today the standard services of a good PVT lab can provide for experimental determinations onreservoir fluids up to pressures of 700 Kg/cm2 (10000 psi) and temperatures of 150 °C (300 °F).The most well equipped labs have instruments which can operate up to values of 1,000 Kg/cm2

(15000 psi) and 200 °C (392 °F).

The most reliable technology in use today is based on windowed PVT cells and motorized pumpswhich work with mercury and mercury-free systems. The most updated apparatus can workcomputer assisted.

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2. RESERVOIR FLUIDS SAMPLING

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2.1 AIM

The aim of sampling is to collect a sample which is representative of the reservoir fluid atthe time of sampling.

Sampling must be considered just as important as subsequent lab analyses, in order toensure a final result which is accurate and reliable.

The PVT study supplies characteristic data of the collected sample.

Irrespective of the accuracy of the study, the quality of experimental lab determinations depends onwhether (or not) the tested sample is representative of fluid in the reservoir or at least in the drainedarea of the well.

The sample may not be the true “average” fluid of the whole reservoir and so the results may haveto be slightly adjusted successively.

In any case, the quality of a PVT study and subsequent engineering calculations whichare based on data of the study cannot be better than the quality of the fluid samplesoriginally collected during the sampling.

A good PVT report must include accurate comments on the validity of the samples used for thestudy.It is therefore advisable to carefully read the comments attached to PVT reports.

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2.2 WELL CONDITIONING

One of the most important factors for obtaining representative samples is adequate wellconditioning before sampling.

The “API Recommended Practice for Sampling Petroleum Reservoir Fluids” of theAmerican Petroleum Institute (API RP 44, January 1966), fully describes the recommendedconditioning techniques and different sampling methods.

The aim of well conditioning is to remove non-representative reservoir fluid presentaround the well, by displacing it with original fluid which comes from the furthest part ofthe reservoir.

Well conditioning basically involves managing the well’s flow rates, controlling and recording theproduction trend for as long as possible before sampling and gradually reducing the well’s flow ratein order to:

- reduce the drawdown of bottomhole pressure to the minimum- increase the bottomhole flowing pressure to the maximum- check the validity of the GOR value measurements

During sampling, the GOR value should remain absolutely stable over time and not change withvarying well flow rates.The validity of PVT analysis depends on the accuracy of the GOR value used to recombine theseparator gas and oil samples.When the GOR is not perfectly stable during sampling, but fluctuates, the recombination GOR mustbe calculated as an average value of all the reliable values recorded during the sampling.

Well conditioning before sampling is particularly important in reservoirs with saturated or slightlyundersaturated fluids and in condensate gas reservoirs.

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2.3 METHOD

The choice of sampling method may be affected by several important factors, such as:

• the type of reservoir fluid to be sampled• the degree of reservoir depletion• the well’s flow conditions• the volume of sample to be collected required to complete the entire programme of PVT lab

tests• the well’s location• the type and set up of surface separation equipment available• the mechanical conditions of the hole• the availability of qualified personnel

Depending on the above, one of the following three sampling methods can be used for PVTanalysis:

- bottom hole sampling- well head sampling- surface sampling.

The choice of which method to adopt basically depends on the type of reservoir fluid andon whether it is undersaturated or saturated at formation conditions.

In the case of undersaturated oils, bottomhole sampling is always suggested, if possible.

If the oil is saturated, it is recommended to take gas and oil samples at the 1st stage separator andthen physically recombine them in the lab, according to the volumetric gas/oil ratio (GOR) of theseparator.

In the case of condensate gas reservoirs, irrespective of whether they are saturated orundersaturated, it is recommended to collect samples at the separator. Suitable well conditioningand correct sampling techniques at the separator are particularly important for these types of fluidsand must therefore be carefully carried out.

Conventional sampling of pressurised liquids requires the use of mercury.

In any case it is advisable, whenever possible, to carry out mercury free sampling for light, lowviscosity liquids and this can be done using water as the displacement fluid instead of mercury, orcylinders which are fitted inside with a piston or membrane.

When cylindrical containers fitted with a mobile (floating) piston are used, the sampling procedurestated in the “Standard Practice for Containing Hydrocarbon Fluid Samples Using aFloating Piston Cylinder” (ASTM D 3700-78) should be adopted.This standard is the exact equivalent of the specification “GPA Standard 2174” which issuggested for sampling natural gases using the same type of sampling container.

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Conventional sampling of pressurised gas requires the use of cylinders previously air evacuated.

Pressurised natural gas sampling may be recommended to be carried out according to thestandard “Methods for Obtaining Natural Gas Samples for Analysis by GasChromatography” (GPA Standard 2166, 1986).

Other reference standards include:

- “Standard Method of Sampling Natural Gas (ASTM D 1145 - 1980)- “Sampling Manual ISO 3170”

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2.4 WHEN AND HOW MUCH TO SAMPLE

It is suggested to collect samples immediately at the beginning of the reservoir’s life, preferablyafter a few weeks of production, so that original virgin reservoir fluid can be obtained before theformation pressure, in any case, drops below the fluid saturation pressure.

It is advisable to collect the following, for each tested production interval:

- at least 3 bottomhole samples or 3 well head samples, in 600 cm3 cylinders

- and/or at least 3 separator gas samples in 20 litre cylinders and 3 separator oil samples in 600cm3 cylinders.

This is the minimum number needed for checking the reciprocal consistency of the samples.

In normal conditions, this number of samples is sufficient to ensure a reservoir fluid volume forperforming a complete PVT study (1 litre for the oil studies and 0.5 litres for the condensate gasstudies).

If separator pressure is very low (less than 10 kg/cm2) and the GOR is higher than 300 Nm3/m3, itis advisable to collect at least six cylinders of separator gas.

If the works programme to be carried out at the PVT lab is more complex than the standard oneand includes multistage separator tests, swelling tests or miscible displacement tests, the volumeof samples to be collected must be agreed on beforehand with lab experts.

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2.5 DOCUMENTS

It is to be pointed out that the documents containing the sampling data must accompany thesamples and that the Production Test Report must be sent to the PVT lab appointed to carry outthe study.The information included in these documents is used to check the validity of samples, makecomparisons between field test data and lab test data, and obtain reliable data for the accuraterecombination of separator gas and liquid samples.

In all cases, documents containing sampling data and the production test report shouldbe attached to the PVT works programme.

During sampling, the reservoir and test parameters listed below must be measured and recordedon sampling documents.

• initial static pressure of the reservoir• flowing pressure at the sampling depth• reservoir temperature for the studied production interval• well head temperature and pressure• separator temperature and pressure• flow rates of stock-tank oil, separator oil and separator gas• characteristic factors of separator gas (Z, d or Fpv, Fg)• separator oil volumetric shrinkage factor (Fsh)• Bottom Sediment & Water (BSW)• water cut• API gravity of stock-tank oil• GOR, volumetric ratio between 1st stage separator gas and stock-tank oil produced• pour point• remarks on prevailing conditions during sampling (for example, how long the well has been

stabilised for, how stable flow conditions were, whether sampling was carried out using mercuryor water, whether H2S and/or CO2 are present, etc.

In the case of bottomhole sampling, the flowing pressure at the sampling depth is extremelyimportant and must be significantly lower than the saturation pressure of the sampled fluid, atreservoir temperature.

In the case of sampling at the separator, the GOR measurement is extremely important.As this parameter is a consequence of gas and oil flow rate measurements, it is worth requestingand checking that the measurement tools which are used, conform to standards and have beenproperly calibrated.

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Reference should be made to the following standards for measuring gas flow rates:

- “Volumetric Measurement by Displacement Metering System” (ISO 2714, API Ch 5.2)- “Volumetric Measurement by Turbine Metering System” (ISO 2715, API Ch 5.3)- “Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids” (GPA Standard

8185, AGA Report 3, API/ANSI 2530 Standard).

Reference should be made to the standard below, for measuring liquid hydrocarbon flow ratesusing a turbine-flowmeter:

- “ANSI Publication 2101 (1981)”.

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2.6 SAMPLING CONTAINERS

Pressurised samples must be collected in steel containers, usually cylindrical, with or without aninternal moving piston, correctly designed to support high pressures and these must be accuratelypacked for safe transport to the lab.

These containers must be certified by recognised institutes (for example Lloyds Design Approval,Bureau Veritas Certification), or by the actual manufacturers who guarantee the integrity ofmaterials and technical performance at working pressures.

It should be noted that cylinders for sampling pressurised hydrocarbons must comply with nationaland international standards on transport. For example, in the USA, the “Hazardous MaterialsRegulations of the Department of Transportation” and in Italy the regulations issued by the Ministryof Transport for compressed, liquefied and dissolved gas containers destined for road transport(DM 12-9-25 and subsequent Integrative Provisions).

Pressurised cylinders are also subject to IATA regulations in the event of air transport and IMDGregulations in the event of sea transport.

In the case of sampling pressurised fluids which contain H2S, it is possible to use teflon-linedcylinders equipped with a piston to prevent the fluid’s contact with mercury or other auxiliary fluids.

When H2S, mercury or any other toxic product can be present in the sampling cylinders specialdeclaration and shipping cautions are requested.

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2.7 FIELD CONTROLS

In the case of bottomhole sampling, some simple field tests can be performed to check whether ornot the collected samples are reliable.

The main test is for determining the saturation pressure of the collected sample.This involves injecting mercury or any other hydraulic liquid into the sampler by a step by stepprocedure to pressurize the sample progressively.The relation between the injection pressure and the cumulative volume of injected fluid can be usedto calculate the following properties:

- the pressure inside the sampler when it came up to the surface

- the fluid saturation pressure at field temperature, identified as the discontinuity point on the“pressure-volume” plot.

If two or more of the samples collected at a short time interval from each other have thesame measured properties, it is highly likely that representative and reliable samples havebeen collected.

The fluid contained in the sampler is transferred by a pump to a high pressure cylinder suitable fortransport to the lab.This operation should be done at high pressure conditions to assure monophase fluid flow, to avoidjeopardising the validity of the collected sample. , taking all necessary precautions

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2.8 SUGGESTIONS

When it is particularly hard to identify the optimum depth for positioning the sampling tool, duringbottomhole sampling, because of water in the well, it is advisable to open the first collected sampleto check its contents. If most of the collected fluid is water, a different and more suitable samplingdepth can then be chosen for the other run.

Bottomhole sampling should be carried out with the well flowing through the smallest chokepossible. This makes it possible to keep the pressure “drawdown” at minimum, the flowingpressure high and have new virgin reservoir oil constantly flowing into the well.

It is also possible to perform bottomhole sampling with the well closed.In this case, it is advisable to collect different samples at various depths.

If there are any doubts about collecting representative fluid samples (for example fluids which areslightly undersaturated), if a well is particularly important in strategic-economic terms, and ifsampling repetition does not seem possible in the future, it is suggested to perform bothbottomhole and separator sampling at the same time.This sampling approach is also recommended when a large volume of reservoir fluid is required(10 - 20 litres) for performing a complex scheduled programme of thermodynamic studies.

The comparison between bottomhole samples and recombined samples may be useful for a betterunderstanding of the real reservoir fluid.

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3. CONTROLLING THE VALIDITY OF SAMPLES

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As the representativeness of a PVT study depends a great deal on sampling conditions, the firstand most important action, before proceeding with the complete reservoir fluid study, is tocheck the validity of samples.In all cases, each sample, whether collected bottomhole, at well head, or at the separator must becontrolled to check its validity.

The reciprocal consistency of a set of samples collected in similar conditions is checked asfollows:

- in the case of bottomhole liquid (BHS) or well head (WHS) samples,by determining the saturation pressures at ambient temperature, and in extreme cases, atreservoir temperature. The results are then compared to reservoir static pressure and flowingpressure values.If the saturation pressures of at least two samples are similar to each other, with a reciprocaldeviation below 2%, and if these saturation pressures are below reservoir pressure and flowingpressure values, the samples may be considered as reliable and representative of reservoirfluid.If the samples have saturation pressures which differ from each other with deviations above 2%,then the problem exists of deciding which sample is the most representative or whether allsamples are unreliable. This problem is handled by PVT and reservoir experts and is solvedcase by case.

- in the case of separator liquid samplesby determining their saturation pressures at separator temperature.Their saturation pressure must coincide with separator pressure value.

- in the case of separator gas samplesby determining the cylinder opening pressure, the air content and chemical composition of thegas mixture. Prior to this, the cylinder must be heated to a temperature above the separatortemperature to ensure the vaporisation of all components.The opening pressures of every cylinder must be close to the separator pressure value,no air must be present in the samples (< 1% mol.) and the composition of all samples must bestrictly identical each other.

In the case of volatile oils, due to their extremely elastic behaviour, it is advisable torequest validity tests to be carried out in a windowed cell, at reservoir temperature.

In the case of condensate gas samples collected from the bottomhole, the validity testsmust be carried out by determining the Dew Point of each sample in a windowed cell atreservoir temperature.

The samples will be consistent if they have the same Dew Point and are valid if the Dew Point islower than the reservoir pressure value.

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4. CHEMICAL COMPOSITION OF RESERVOIR FLUIDS

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4.1 PRESSURISED LIQUIDS

The most common procedure for determining the chemical composition of pressurised liquids(reservoir oils, separator oils, etc.) is known as the “blow-down method”.

A flash test is directly performed on a fairly large volume of liquid at atmospheric pressure, thus twostabilised phases are produced: a gas and a stock-tank liquid phase.The volumetric ratio between the released gas and the stock-tank liquid is measured (GOR).The compositions of the produced stock-tank liquid and released gas are then determined bydistillation (mini-Podbielniak, Fisher or other methods) and gas chromatography respectively, usingthe techniques mentioned in the next sections.These compositions are usually determined up to the fraction C13 plus for liquid and up to thefraction C7 plus for gas.Extended liquid and gas analysis are possible if specifically requested.These compositions are then recombined using a specific calculation procedure, according to thevolumetric ratio of the two phases (GOR) measured during the test, in order to obtain the calculatedcomposition of the original fluid, usually up to C13 plus.

This procedure is suitable for samples of separator oil, well head and bottom hole oil, for which theerror inherent to measuring the volumetric ratio (GOR) is fairly small.

This technique is less accurate for rich gas mixtures (condensate gas), where the volume ofcondensate which is developed as a result of the blow-down is moderate (high GOR values).

In these cases, particular (not-standardised) techniques can be used to recover all the condensablecomponents and these should be agreed on with the PVT lab in order to obtain the most accurateinformation on the percentages of the heavier components present in the mixture.

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4.2 H2S IN PRESSURISED LIQUID SAMPLES

When hydrogen sulphide is present in pressurised liquid samples, it is advisable to check that thesample has been collected in teflon-lined cylindrical containers, equipped with a floating piston.

Afterwards, in the lab, the sample undergoes a “flash test” directly at atmospheric pressure (blow-down method) and the percentage of H2S present in the released gas must be immediatelymeasured using one of the ASTM or UOP measurement methods for sour gas analysis.

The composition of gas with that of stock-tank oil are the recombined by calculation to obtain theconcentration of H2S in the original pressurised liquid.

If it is not possible to use teflon-lined cylinders, we suggest carrying out this measurement asquickly as possible after the sample has been collected, to avoid the consumption of H2S causedby its reaction with the steel of the cylinders.

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4.3 PRESSURISED GAS

The samples of separator gas and natural gas are generally analysed using gas chromatography(GC Method).

The gas sample is injected into a gas chromatograph equipped with packed columns as per IP354 standards; the chromatograph may be modified with capillary columns to improve itsperformance.

Raw chromatographic data are compared to those of a standard gas and normalised to 100.The analysis is then corrected, by adjusting the values in relation to any air present.

The results are expressed as a molar % of single components up to n-C5 and of the C6 family;these results include the determination of non-hydrocarbon permanent gases such as O2, N2,CO2, H2S and usually group the heavy components such as C7 plus.

In particular cases when gases are very rich or greater precision is required, determinations whichextend to C15 plus components may also be carried out, when appropriate equipment is available.

Reference should be made to the following international standards for natural gasanalysis:

- GPA Standard 2261 - 90

- ASTM D 1945

- ISO 6974

It is advisable to request the chemical gas composition to be determined immediately on siteat the field when:

- immediate results are needed- hydrogen sulphide or other sulphide gas compounds are present- the well is located in distant places.

The following advantages may be achieved by this approach:

- good quality and immediately available results

- more accurate and reliable values on the content of those components (H2S) which couldchemically react with the material (steel) of the sampling container and/or with other componentspresent in the gas mixture (CO2, H2O vapour).

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4.4 H2S IN PRESSURISED GAS SAMPLES

Hydrogen sulphide in the gaseous phase should preferably be directly determined on site at thefield as this component is absorbed in different degrees by the metal surface of the containersused for sampling.

The measurement technique used to determine the amounts of H2S depends on the value of theH2S concentration to be measured and on the degree of precision required.

Basically speaking, the following methods are adopted:

- Adsorption with the Draeger tube -

This is a quick method, which can cover a wide range of concentrations, from 1 ppm to a 7%volume (70000 ppm) and the accuracy of measurements varies from 5% to 10%.

- Tutweiler Burette (UOP 9-69) -

This measurement method is more accurate than the previous one, but can only be applied to H2Sconcentrations above 100 ppm. If mercaptans are also present, these are measured as H2S.

- ASTM D 2385 (IP 103) -

This measurement method is even more accurate and able to distinguish gaseousH2S frommercaptans. It is still based on the principle of adsorption.The gas is forced to flow through a train of adsorbers, with the first two of them containing cadmiumsulphate to adsorb the H2S and the third containing a mixture of cadmium sulphate and hydroxideto adsorb the mercaptans.The accuracy of results is ± 1%.This method is the same as the IP 103 method and the GPA Standard 2265 “Method forDetermination of Hydrogen Sulphide and Mercaptan Sulphur in Natural Gas (Cadmium SulphateIodometric Titration Method)”.

Other standardised methods which can be used are:

- ASTM D 2725-70, a methylene blue colorimetric method, for H2S concentrations below 50 ppm.- UOP 212/77, using potentiometric titration, for any H2S concentration.

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4.5 CO2 IN PRESSURISED GAS SAMPLES

The following techniques for measuring CO2 can be performed at the field, when a gaschromatograph is not available:

- The Draeger tube-

This is an adsorption method for the quick determination of a wide range of concentrations, thoughvalues are approximate.

- Orsat (UOP 172) -

This is a simple, chemical method, which can be used with precision only for CO2 concentrationsabove 0.2%; a known volume of gas is put in contact with a solution of sodium hydroxide that reactswith the CO2, subtracting it from the gaseous phase; the CO2 concentration is then determinedaccording to the reduction in the gas volume.

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4.6 STOCK-TANK LIQUIDS

The composition of stock-tank liquids is determined using the procedure in the attached flow chart.

The oil is first distilled in a special packed column according to a procedure which complies withinternational Standards (mini-Podbielniak, Fischer or other ASTM methods).The distillation makes it possible to separate the highest boiling point and heaviest fractions(residue) from the lightest and intermediate ones.The lightest fractions are then analysed by gas chromatography.The intermediate fractions are analysed by gas chromatography using capillary columns.The residue is characterised by experimentally determining its molecular weight (using cryoscopy)and specific weight (using a U-tube type vibrating densimeter).In most cases, the residue consists of C13 plus components, but a more detailed analysis - evenup to C25 plus and/or C30 plus components - can be performed, by distilling at temperatures of350°C and using capillary column equipment. The packed columns are easier to be used thancapillary ones, but the latter produce closer peaks which make it possible to identify a greaternumber of single components and so they are more selective.

The overall results are expressed as weight %, then converted to molar %, for single componentsup to n-C5 and for pseudo-components for the heavier than C5 family up to the Cn plus residue.

The distillation methods are standardised, and the most widely used are:

- ASTM D 2892 -

Vacuum distillation which can separate components up to the C20s, corresponding to a TBP (“TrueBoiling Point Distillation”) with 15 theoretical plates.

- ASTM D 1160 -

Strong vacuum distillation, but up to 400°C, corresponding to the UOP 109 standard, which makesit possible to extend the analysis beyond the C20s.

- ASTM D 158 -

Saybolt distillation, up to 350°C.

- ASTM D 216 -

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Engler distillation, suitable for extremely volatile liquids.

- ASTM D 285 -

Hempel distillation, equivalent to the UOP 77 standard, but which characterises liquids cuts bydistillation temperature intervals rather than by single components.

- ASTM D 1078 -

Distillation suitable for liquids with a restricted distillation range.

- ASTM D 86 -

Distillation equivalent to the IP 123 standard, suitable for oil products in general.

The best distillation method to be used can be agreed on, case by case, with the lab technicians.

A good quality PVT report should mention the method used to determine the chemicalcomposition of the fluids analysed.

The composition of stock-tank oil can also be determined using the ASTM D2887 gaschromatography technique (“Gas chromatographic simulated distillation technique”).

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STOCK-TANK OIL

DISTILLATION

LIGHT FRACTION INTERMEDIATE RESIDUE FRACTION

GC ANALYSIS CAPILLARY MEASUREMENTS OF:GC ANALYSIS SPECIFIC WEIGHT

MOLECULAR WEIGHT

MOLAR COMPOSITION MOLARCOMPOSITION

RECOMBINATION

MOLAR COMPOSITIONOF STOCK-TANK OIL

Flow Chart of the procedure for determining the chemical composition of stock-tank oil.

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Upon request, other analyses can be performed on the stock-tank liquids, such as:

- PNA analysis -this is suggested when request is made to determine the relative proportions of paraffin, aromaticand naphthenic compounds.

- fingerprint analysis -this is a gas chromatographic technique where liquid hydrocarbons can be compared by simplevisual examination of the raw chromatogram, without having to identify the single components anddetermine their concentration; the result provides an estimate of the oil’s origin.

- paraffin deposition -the simplest indicators to assess the probability of paraffin deposition during production are:

- the cloud point, to be determined according to the standards ISO 219 / ASTM D 2500- the pour point, to be determined according to the standards IP 15 / ASTM D 97 / ISO 3016.

The specific definitions of these two parameters are stated in the ISO 1998 standard.

Basically speaking, the “cloud point” is the minimum temperature at which the liquid goes cloudy,due to the formation of a cloud of precipitating paraffin crystals.As the method is visual, it can only be used for clear and transparent liquids. For dark fluids, thecloud point is determined instead using non-standard methods such as “differential scanningcalorimetry (DSC)” or tracing the “viscosity-temperature” profile of the oil.The ”pour point” is the minimum temperature at which liquid flows.

The concentration of paraffin in oil is expressed as a % by weight and is determined byprecipitating the waxes at a temperature of - 30°C, after having removed all the asphaltenespresent (BP 237).

- concentration of water -water emulsified in oils can be determined using one of the three methods below:ASTM D 95, ASTM D 4006, IP 358, based on distillation of a fluid sample using Dean & Starkequipment, with a good rate of precision, widely used for liquids with a water content of more than0.5% in volume;ASTM D 4377, IP 356, based on Karl-Fischer potentiometric titration. These standards areadvised for water concentrations below 0.5% in volume;FINA Aquatest, a simple, quick method which is less accurate than the others and can be usedmainly for field measurements on site.

- B S & W -The percentage of bottom sediment and water can be determined using three equivalent methods,ASTM D 96, ASTM D 4007, IP359, which are all based on the centrifugation of a sample prepared

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by mixing 50% oil with 50% toluene saturated with water; the value obtained is usually lower thanthe actual value.

It should be noted that the terminology and definitions concerning the various types ofwater present in crudes are stated in the standard ISO 3171

- viscosity -The kinematic viscosity of oil is determined using the ASTM D 445 method, which is equivalent tothe IP 71 method and the ISO 3104 standard and valid for hydrocarbons mixtures of Newtonianrheological behaviour.The time needed for a given liquid volume to flow through a calibrated capillary viscosimeter underthe action of gravity, at a controlled temperature, is measured.The measurement can be taken at different temperatures and expressed as centistokes.The range of measurement is wide, up to 300,000 cSt, depending on the type of capillaryviscosimeter used.The dynamic viscosity, expressed in centipoises, is obtained by multiplying the kinematic viscosityby the density of the stock-tank oil at the same temperature.

- density -the density of stock-tank oil, even at different temperatures, can be determined using one of thestandard methods below:- ASTM D 1298, using a hydrometer- ASTM D 4052, using an Anton Paar digital densimeter- IP 190, using a Warden or Hubbard capillary picnometer.

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5. PRELIMINARY TESTS AND RECOMBINATIONS

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The main preliminary lab tests involve:

- determining the volumetric shrinkage factor which characterises separator oil. A “flash test”is performed on the sample from separator pressure to atmospheric pressure. The value of thisfactor is always less than 1 and depends on the type of oil; usually for each type of oil this valuedecreases as the separator pressure increases.

- measuring the density of the separator oil under separator conditions. For this purpose, use ofan Anton Paar densimeter is suggested.

The physical recombination of separator fluids involves creating a significant volume of reservoirfluid in a PVT cell; this is done by mixing gas with separator oil in the right volumetric proportions.

In most cases, the right volumetric proportions are given by the GOR (volumetric Gas/Oil Ratio)measured at the field and adjusted:- for the shrinkage factor of the separator oil, taking into account the separator’s operating

conditions- for the gas density determined at the field (Fg = 1/ √ d) and in the lab- for the gas compressibility factor determined at the field (Fpv = 1/ √ z) and in the lab.

In some cases, the recombination GOR is immediately available, expressed as the ratio

“Nm3 of separator gas / m3 of separator oil at separator T&P”

The physical recombination should be done at least twice, to confirm that during two separate andindependent tests the recombined fluid has the same saturation pressure.

When the validity of the GOR value measured at the field is uncertain, it is advisable to request apreliminary “GOR - Saturation Pressure” study, where several separate recombinations usingdifferent GOR values are performed and the saturation pressure value of each mixture isdetermined. A study of the results, compared to reservoir conditions, can clarify which is the truefluid present in the reservoir, in terms of reliability.This preliminary study is especially recommended for condensate gas.

Sometimes instead of GOR is preferred to present a GLR (volumetric Gas/Liquid Ratio) or a CGR(volumetric Condensate/Gas Ratio)

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6. REQUESTING A PVT STUDY

This section describes the typical tests to be requested for performing a complete PVT study onthe following types of reservoir fluid:

Dry gases

Oils (heavy, medium, light)

Volatile oils

Condensate gas

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6.1 Reservoir fluid: DRY GAS

General information

Dry gas is defined as a mixture of hydrocarbons (usually natural gas) with a chemical compositionwhich is such that no condensate liquids are produced, not even at the surface plants.

When minimum amounts (often negligible) of condensate liquids form, the gas is defined as wetgas.

These types of gas are characterised by a GOR value above 35,000 Nm3 / m 3 (200 MScf/bbl).

A dry gas may be correctly sampled at both the well head and separator.

Whenever traces of condensates are produced at the separator or tank, these should be taken intoaccount and sampled in order to obtain a correct evaluation of the reservoir fluid.

Fig. 1 shows the procedure adopted during the PVT study for dry reservoir gas.

Controlling the validity of samples -

According to the procedures stated in section 3.

Chemical composition of reservoir gas

Determined according to the procedures stated in section 4.

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Compressibility factor (z) of reservoir gas -

This determination is the most important for characterising the volumetric behaviour of gas andmust be carried out at reservoir temperature (Tg).

The z factor, also known as the “gas deviation factor” is determined within a range of pressuresfrom reservoir pressure to atmospheric pressure.

The volume taken up by the gas at reservoir temperature and many pressures (at least six differentones) is measured, in conditions of thermodynamic equilibria, in a PVT cell fitted with anobservation window.

The gas is then displaced from the cell and collected in a volume measuring device at atmosphericpressure to determine the Nm3 equivalents (standardised or normalised value, Vs).

The z factor at the i-th pressure is calculated using the expression

Pi * Tstandard Viz = --------------------- * --------------

Tg * Pstandard Vstandard

Note thatTstandard = 273 + 15 = 288 °K = 60 °FPstandard = 1,0332 Kg/cm2 = 0.10 MPa = 14.7 psia

The results are plotted on a graph and enable the z = f (P) curve to be traced at reservoirtemperature.

It may also be important to know the z value of a dry gas at temperatures other than reservoirtemperature. In these cases it is advisable to ask the PVT lab to determine the z factor, even attemperatures of specific interest.

Measuring the z value is advisable, especially for gases containing non-hydrocarbon products suchas CO2, H2S, N2 which change the real gas behaviour a great deal if compared to the ideal gasand therefore make the theoretical methods for determining z values less reliable.

The observation window is used to check whether any amounts, even minimum, of condensedproducts, form when the pressure decreases and the cell cools down to ambient temperature.

Gas density -

34

The density of reservoir gas, at reservoir conditions, can be experimentally determined using anAnton Paar densimeter.

The density of the same gas at atmospheric conditions is usually calculated on the basis of thechemical composition.

Gas viscosity -

Reservoir gas viscosity, at reservoir conditions, is suitably calculated on the basis of the gaschemical composition.

Potential liquid products -

These are defined as “the volumetric amount (m3 at 15 °C) of liquid which could be produced by 1Million Nm3 of initial gas at reservoir pressure, if it were possible to liquefy all the hydrocarboncomponents, from C3 to the heaviest (C3 plus), from C4 to the heaviest C4 plus), from C5 to theheaviest (C5 plus)”.

This data is calculated and presented as “m3 / MM Nm3” (gallons/MM Scf).

35

GAS SAMPLES

VALIDITY CHECK OF SAMPLES

COMPOSITION OF RESERVOIR GAS

SELECTION OF THE MOSTREPRESENTATIVE SAMPLE

EXPERIMENTAL EXPERIMENTAL DENSITY Z FACTOR

CALCULATEDGAS DENSITY

CALCULATEDGAS VISCOSITY

CALCULATED POTENTIAL LIQUID PRODUCTS

Fig. 1

36

6.2 Reservoir fluid: OIL

General information

Oil is defined as a mixture of hydrocarbons which, in reservoir conditions, are liquid and which, atpressures below the saturation pressure (bubble point) give rise to a continual and cumulativeshrinkage of the volume of liquid as a result of gas being released.

A distinction is made among heavy, medium and light oils, depending on the amount of gasdissolved in these oils and the characteristics (viscosity and specific weight) of stock-tank oil.

The GOR values which characterise these oils are as follows:

heavy oils 0 < GOR < 50 Nm3/m3medium oils 51 < GOR < 200 Nm3/m3light oils 201 < GOR < 350 Nm3/m3

An oil may be correctly sampled at the bottom hole, well head or at the field separator.Depending on the type of samples available, the stages of the PVT study are performed accordingto different procedures.Fig. 2 shows the procedure for performing a PVT study on reservoir oil samples collected from thebottom hole or at the well head.Fig. 3 shows the procedure for performing a PVT study on reservoir oil obtained by recombiningthe fluids sampled at the separator.

Validity check of samples -


Chemical composition of reservoir oil


37

Constant composition expansion -

This is a classic test performed at reservoir temperature to determine the saturation pressure(bubble point pressure) of the reservoir fluid, i.e. the pressure at which the first gas bubble isreleased from the liquid. It is labelled as CCE test.

The above is also known as “Constant Mass Expansion” and as the “Pressure-Volume relation”.

DESCRIPTION -

A sample of fluid, inside a windowed PVT cell adjusted to reservoir temperature, is submitted todepletion; this involves applying a series of thermodynamic equilibria at various pressure steps andexperimentally determining the volumes occupied by the mixture at equilibrium conditions.No other fluids are removed or injected in the cell during the test, resulting in a constant mass andconstant composition expansion.

The saturation pressure value is identified by visual inspection and by the point of discontinuityon the “pressure-volume” curve.

REMARKS -

The number of equilibrium pressures (steps) to be investigated depends on reservoir pressureand on bubble point pressure values.Usually, 8 steps are sufficient, four above and four below the bubble point.At least 10 equilibrium pressure steps are recommended for light oils and high reservoir pressures.The test is performed succesfully on fluid volumes of approximately 150-200 cm3. New PVTmercury-free apparatus allow to carry out the CCE test with 30 cm3 of reservoir fluid.

The test is non destructive, and can therefore be repeated several times on the same sample.

RESULTS -

The following parameters are calculated from the CCE test and indicated in a standard PVTReport :

Relative VolumeThis is the ratio between the volume of the mixture at the i-th general equilibrium pressure and thevolume of the same mixture at bubble point pressure. This value is adimensional.

Isothermic Oil Compressibility

38

This is calculated from the experimental volumetric measurements, using the following ratio:

2 (V1 - V2)c = -------------------- * ------------------

(V1 + V2) (P1 - P2)

and is calculated for one or more pressure intervals, ranging from reservoir pressure to saturationpressure.

The compressibility of oils is greater when the oils are light, the temperature higher and thepressure lower.The unit of measurement is m3/(m3 x MPa), or in other words 1/MPa.

the Y functionThis is an adimensional parameter defined by the ratio

P sat - Pi -----------------

PsatY = --------------------------------- Vi - Vsat

----------------- Vsat

This parameter represents the deviation percentage of pressures in relation to the deviationpercentage of volumes, compared to saturation conditions, for each generic equilibrium pressurePi.The parameter is only calculated for pressures values below saturation pressure, and so only in thebiphase range. In this field, the experimental volumetric data, if corrected, must produce Ycalculated values which must lie on a straight line, when plotted on a graph as a function ofpressure,:

Y = a + bP

All these results are shown on a graph and in a suitably set out table.

39

Differential vaporization -

This is a conventional test performed to simulate the behaviour of original reservoir oil duringreservoir depletion from initial pressure to atmospheric pressure.In the case of heavy, medium and light oils (black oils) it is worldwide acknowledged that differentialvaporisation is the process which satisfactorily approximates the phenomena which occur in thereservoir during its depletion.

DESCRIPTION -

A reservoir fluid sample, previously transferred in a windowed PVT cell at constant reservoirtemperature, is submitted to a series of equilibria steps at different pressure values, whichgradually decrease according to a programme previously scheduled according to thecharacteristics of the oil to be tested.The volumes assumed by the mixture at equilibrium conditions are measured at each pressurestep.At each pressure value lower than the saturation pressure of the original oil, a gas phase developswhich is in equilibrium with a liquid whose properties are different if compared to those of theoriginal oil.All the gas which has been released is therefore transferred outside the cell, at constant pressureto avoid changing the thermodynamic equilibrium, and is collected in a suited sampling device.The volume, density, z factor and chemical composition of the gas are then determined.At the final pressure stage, the oil which has remained in the cell undergoes flashing up toatmospheric pressure, thus producing degassed residual oil.The residual oil is measured and recovered in order to determine the specific weight atatmospheric pressure at 15°C and at reservoir temperature, using an Anton Paar densimeter.For more accurate characterization studies the chemical composition of the residual oil isdetermined too. It is suggested for light and volatile oils in particular.

REMARKS -

Each pressure step is usually in the range of 30 Kg/cm2 (450 psi).The number of pressure steps to apply depends mainly on the bubble point value of the original oil.Oils with a high bubble point (from 150 to 250 Kg/cm2, 2200 - 3600 psi) require approximately 6-7pressure steps below the bubble point, while oils with a low bubble point (up to 50 Kg/cm2, about700 psi) only need 3-4 pressure steps.The mass and composition of the mixture are variable during the test execution and so this type oftest is destructive.It cannot be repeated, unless a new volume of the whole original sample is used.The test is performed consuming 200-250 cm3 of fluid with the standard equipment.With the new PVT mercury-free apparatus and suited sampling techniques also 30-40 cm3 ofreservoir fluid sample may be suitable for reliable results.In order to ensure accurate results, the best labs perform a global mass balance and a molecularmass balance of each component as a control, to verify that the initial quantity of hydrocarbons hasbeen recovered both as gas and as residual oil.

RESULTS -

40

The parameters below are then calculated from the experimental raw data of this test and includedin the standard PVT Report.

- gas solubility -This is the volume of gas dissolved in the oil at any given pressure. It is indicated by the symbol Rsand expressed as Nm3 of dissolved gas for every m3 of residual oil at standard conditions (SC,15°C and atmospheric pressure).

- reservoir oil volume factor -This is the ratio between the volume of oil which remains in the reservoir at any given pressure andthe volume of residual oil at standard conditions. It is indicated by the symbol O.R.V.F. or Bo, andexpressed as m3 (T&P) / m3 (SC). The value is always greater than one.

- total volume factor -This is the ratio between the sum of the equilibrated oil and gas phase volumes, at reservoirtemperature and at any given pressure, and the volume of residual oil at standard conditions. It isindicated by the symbol Bt and is expressed as m3 (T&P) / m3 (SC).

- reservoir oil density -This is the specific weight of oil at any given pressure, at reservoir temperature. It is expressed asKg / m3 (T&P).

- gas density -This is the density of equilibrium gases, determined at 15°C and at atmospheric pressure, relativeto air in the same conditions. The value is adimensional.

- z factor -This is the deviation factor of gas in equilibrium conditions in relation to ideal gas behaviour. Thevalue is adimensional.

- gas volume factor -This is the ratio between the volume occupied by a given mass of gas in equilibrium conditions atreservoir temperature and at any given pressure and the volume occupied by the same mass ofgas at standard conditions. It is indicated by the symbol Bg and is expressed as m3 (T&P) / Nm3(SC).

- chemical composition of gas -This is the composition of each equilibrium gas released by oil at reservoir temperature during thetest. It is expressed as a mole % for each single component.

All these results are given in the PVT Report as both tables or graphs.

Separator tests -

41

These are a set of “flash tests” performed to simulate the production process in order to determinethe separator pressure value which can ensure maximum recovery of stock-tank oil (degassed) at apre-defined separation temperature.At the same time, the volumetric coefficient which quantifies the maximum recovery compared to oilavailable in the reservoir is determined.

DESCRIPTION -

A measured volume of a sample of the reservoir oil is removed from a PVT cell at constantpressure and in monophase conditions and is suddenly expanded (flash test), through a valve in awindowed container (separator) which is kept at a constant separation temperature and previouslypressurised with inert gas to the chosen operating pressure.The reservoir oil which is injected into the separator produces a gas and a liquid (separator gasand oil), which are assumed to reach a condition of thermodynamic equilibrium at separationconditions.During the test, in order to maintain a constant separation pressure, the gas is continually removedfrom the top of the container, allowing it to flow into a sampling equipment which is suitable fordetermining the volume, density and chemical composition.The separator oil is then depressurised until it reaches atmospheric pressure, with an additionalvolume of gas being released and fully degassed stock-stank oil being produced.

This test is defined as a single stage separator test.

REMARKS -

A set of single stage separator tests is usually performed at the temperature which is expected tohappen during production at the field.These tests usually involve at least four different operating pressures of the first stage separator.The pressure values to apply are chosen on the basis of the studied oil properties.High separation temperatures (from approximately 50 to 70 °C) and low separation pressures(below 10 Kg/cm2) are expected for heavy oils, while higher separation pressures (from 30 to 50Kg/cm2) and temperatures in the range between 20 and 30 °C are expected for light oils.

If requested, the tests can be repeated, at different separation temperatures, in order to perform amore complete study.

The tests are destructive as they lead to the irreversible consumption of the sample used.Repeat tests therefore require additional amounts of sample. Each set of four independent testsrequires about 200 cm3 of fluid.

Multistage separator tests may also be requested, which means that the separation processtakes place in several cascade stages. These tests simulate a complex separation system, and

42

are recommended for volatile oils only, where a separation process through multiple stages mayprobably be designed, in order to maximise the production of condensates.

Each separation stage takes place at temperatures and pressures which are constant yet differentfrom those of other stages.

There is no standard lab equipment suitable for these tests. Usually the tests are carried out byassembling in cascade a series of PVT cells for the high pressure separation stages, withtraditional separators for the remaining low pressure stages.

RESULTS -

The parameters below are then calculated from the results of this test and included in the standardPVT Report.

- oil formation volume factor -This is the ratio between the volume of oil available at reservoir temperature and at bubble pointpressure and the volume of stock-tank oil which could be produced through a separation systemoperating at the indicated separation temperature and pressure. It is indicated by the symbolO.F.V.F. and expressed in m3 (T&P) / m3 (SC). The value is always greater than one.

- separator oil volume factor -This is the ratio between the volume of separator oil, at the separator’s operating temperature andpressure, and the volume of the resulting stock-tank oil at standard conditions. It is indicated by thesymbol O.V.F. and is expressed in m3 (T&P) / m3 (SC). The value is always greater than one.

- Separator GOR -This is the ratio between the gas volume (measured in standard conditions), released by thereservoir oil at the separator and the volume of stock-tank oil produced and associated to it.It is expressed in Nm3 / m3 (SC).

- Stock-tank GOR -This is the ratio between the gas volume (measured in standard conditions), released underatmospheric pressure by the separator oil and the volume of stock-tank oil produced andassociated to it.It is expressed in Nm3 / m3 (SC).

- Total GOR -

43

This is the ratio between the total gas volume (measured in standard conditions) released in theseparation system by reservoir oil and the volume of stock-tank oil produced and associated to it.It corresponds to the sum of the two previous GOR values and is expressed in Nm3 / m3 (SC).

The results of the tests are completed by experimentally determining:

- the chemical compositions of the gases released at the separator and tank;- the density (API gravity) of the stock-tank oil produced;- the viscosity of the stock-tank oil produced, measured at the studied temperatures.

All these results are given in the PVT report both as tables and graphs.

44

Viscosimetry -

Viscosimetry is a test performed to determine the dynamic viscosity of reservoir oil at reservoirtemperature and at a range of pressures values between the original reservoir pressure andatmospheric pressure.For pressures values above the saturation pressure of the reservoir oil, the viscosity of the integraloriginal oil is measured.For pressures values below the saturation pressure of the reservoir oil, the viscosity of theequilibrium liquid phase produced during a step-by-step differential process vaporisation ismeasured.

DESCRIPTION -

A rolling ball viscosimeter equipped with a calibrated measuring tube is filled up with reservoir fluidat reservoir temperature.Reservoir pressure is applied and the viscosimeter is shaken until a liquid monophase condition isobtained.The equilibrium pressure required for taking the measurement is then applied according to a step-by-step depletion.At each pressure a small magnet of the viscosimeter is disabled thus enabling a calibrated steelball to roll through the liquid along the calibrated tube. The time occurred for the ball to move alongthe tube is measured.For pressures below saturation pressure, the released gas is collected in the upper chamber of theviscosimeter, thus enabling the calibrated measuring tube to be entirely filled with oil in equilibriumconditions only, in all operating conditions.

REMARKS -

This measuring system is valid for all liquid hydrocarbon mixtures which show a Newtonianrheological behaviour in measurement conditions.It is not possible to take accurate measurements on reservoir oils which have an emulsified watercontent of more than 1% in weight.The viscosities of gases in equilibrium conditions are calculated on the basis of their chemicalcomposition.The viscosity tests are particularly important for medium and heavy oils, with a viscosity above 30cP. In these cases, accurate measurements are required, using accurately calibrated equipment.It should be noted, in any case, that deviations of around 10% from the viscosity values determinedin different labs are possible.

45

RESULTS

The viscosity is calculated using the following equation

u = k t ( d1 - d2 )

where:d1 = the density of the steel balld2 = the density of reservoir oil at the measurement pressurek = the calibration constant of the measurement toolt = the measured timeu = the dynamic viscosity, measured in centipoises (cP).

The results are given in the PVT report, in both tables and graphs.

46

Well Head Samples Bottom Hole Samples

Transfer from the sampling cylinder

Determination of thesaturation pressureand of the P-V relation

Selection of the mostrepresentative sample

Separator Determination Constant mass tests of viscosity study

Blow-down at atmospheric pressure

Differential Vaporization study

Chemical analysis andmathematical recombination

Composition of reservoir fluid

Fig. 2

47

Samples of separator oil Samples of separator gas

Determination of Gas chromatographic saturation pressure analyses

Selection of the most Blow-down at Composition of separator representative sample atmospheric pressure gas

Chemical analysis and mathematical recombination Selection of the most

representative sample

Composition of separator oil

Mathematical recombination of compositions of separator fluids


Physical recombination of samples

Recombined sample of reservoir fluid

Separator tests Determination Constant Mass study of viscosity

Differential Vaporization study Fig. 3

6.3 Reservoir fluid: VOLATILE OIL

48

General information -

Volatile oil is defined as a mixture of hydrocarbons with the same behaviour as that of “oils”, butcharacterised by a “critical point” very close to reservoir conditions.A volatile oil is more correctly defined as a “near critical oil”.

These types of oil are very light reservoir oils (> 45 API), most of them have a high saturationpressure and high volume of dissolved gas.The GOR values of these oils range from approximately 350 to 600 Nm3/m3.They are therefore high shrinkage oils, which, even when just below their saturation pressure,release large amounts of gas enriched with products that are condensable at surface conditions.A traditional PVT study can be conducted on these types of oils.However, in order to simulate their behaviour in the reservoir, it is recommended that these oilsundergo ”constant volume depletion” rather than conventional differential vaporisation as theformer test best represents the depletion process of a reservoir containing these types of oils.

Fig. 4 shows the procedure for conducting a PVT study on volatile reservoir oil obtained by bottomhole or well head sampling.Fig. 5 shows the procedure for conducting a PVT study on volatile reservoir oil obtained byrecombining the fluids sampled at the separator.

Validity check of samples -


Chemical composition of reservoir oil


Constant Composition Expansion -

According to the instructions stated for oils, in section 6.2.

49

Constant Volume Depletion -

This test is performed at reservoir temperature, assuming that depletion takes place in a reservoirwhose volume remains constant. It is known as the CVD test.This test is applied to obtain information on the properties of the oil which remains in the reservoirand on the gases which are produced during depletion.

DESCRIPTION -

A sample of reservoir fluid, previously put into a PVT cell equipped with a long window and set toconstant reservoir temperature, is submitted to a series of equilibrium steps, at pre-set anddecreasing pressures, according to a programme previously defined for the studied oil’scharacteristics.At each pressure step which is above oil saturation pressure, the volume occupied by themonophase mixture in equilibrium conditions is measured.At the saturation pressure of the original oil, the volume occupied by the mixture is accuratelymeasured and this value is assumed as the reservoir volume to be kept constant during thesubsequent equilibrium steps devoted to simulate the depletion process.At each pressure step which is lower than the saturation pressure of the original oil, a gaseousphase develops which is in equilibrium with a liquid oil phase whose properties are different ifcompared to the original oil.The volumes occupied by this oil and by the entire biphase mixture are measured.Then, at constant pressure in order to maintain the thermodynamic equilibrium, the initial constantvolume occupied by the original fluid at its saturation pressure is restored, by removing the excesspart of the equilibrium gas from the cell.This displaced gas is collected in a special sampling device and the volume, density, z factor andchemical composition are then measured.The cycle (expansion at a lower equilibrium pressure, followed by removal of the released gas torestore the constant volume) is repeated several times, until a pressure which is sufficiently low tobe considered as the reservoir “abandonment pressure” is reached.In this situation, the gas cap in equilibrium conditions is measured, by removing it from the PVTcell.The remaining oil undergoes a flash test in a cell, from abandonment pressure to atmosphericpressure. The volume of the released gas and residual oil are measured and the density andchemical composition are determined.

50

REMARKS -

Given the large amounts of gas released, even just below saturation pressure, and the consequenthigh volumetric oil shrinkage, which is characteristic of these types of fluids, it is advisable to applythe first equilibrium at a pressure very close to saturation pressure (about 8-10 Kg/cm2 belowB.P.).In relation to the high saturation pressure value and the large volume of dissolved gas at least 8-10different equilibrium pressure steps need to be applied in order to better describe the depletionprocess of these oils.The abandonment pressure is chosen freely and usually ranges from 30 to 50 Kg/cm2 (450 to 750psi).The mass and composition of the test are variable, so it is a destructive type test.It cannot be repeated, unless a new volume of whole sample is used.The test is performed with 200-250 cm3 of fluid with standard traditional mercury PVT cell.With the new PVT mercury-free equipment and suited gas sampling techniques, also 30-40 cm3 ofreservoir fluid may be suitable for reliable results.In order to correctly and accurately perform this test, a PVT cell fitted with a window which issufficiently long to enable liquid volumes to be measured at each equilibrium is needed.In order to ensure accurate results, the best labs perform a global mass balance and a molecularmass balance of each component so that the initial load of the hydrocarbons is recovered both asgas and as residual oil.

RESULTS -


- reservoir oil shrinkage factor -This is the ratio between the volume of oil at each equilibrium pressure and the volume of originaloil at saturation pressure. It expresses the entity of the reservoir oil shrinkage factor belowsaturation pressure, caused by the release of gas. This value is adimensional.

- cumulative gas produced -This is the amount of cumulative gas produced during the reservoir depletion. It is expressed inNm3 of gas for each 1,000 Nm3 of initial equivalent gas at saturation pressure. It may also beexpressed in moles produced every 100 initial moles.

- z compressibility factor of the gas produced -This is the deviation factor of equilibrium gas behaviour in relation to the ideal gas behaviour. Thevalue is adimensional.

51

- gas volume factor -This is the ratio between the volume occupied by an equilibrium gas mass at reservoir temperatureand at a generic pressure and the volume occupied by the same gas mass at standard conditions.It is indicated by the symbol Bg and is expressed in m3 (T&P) / Nm3 (SC).

- chemical composition of gas -This is the composition of each equilibrium gas released by oil at reservoir temperature during thetest. It is expressed as a molar % for each single component.

- potential liquid products -These are the liquid volumes which could be produced at the surface from each type of gasproduced. These products are calculated on the basis of the chemical composition of the gas andare expressed in m3 of liquid at 15 °C for each 1,000 Nm3 of gas produced.

- cumulative potential liquid products -These are the cumulative liquid volumes which could be produced at the surface in relation to eachdepletion level of the reservoir, starting from a determined amount (volume) of reservoir fluid atsaturation pressure. These products are evaluated theoretically by calculation and expressed inm3 of liquid at 15°C for each 1,000 Nm3 of initial equivalent gas at saturation pressure.

All the other traditional parameters of the Differential Vaporisation test, i.e. Rs, Bo, Bt, etc. can alsobe calculated. However, it is not a standard routine of all labs to include these data in the PVTReport for a CVD test, unless specifically requested.

52

Separator tests -

These tests must be carried out according to the procedures stated for oils.

Some labs do not perform experimental tests, but obtain data by calculating the thermodynamicequilibrium of a flash process; these calculations are performed with suitable PVT softwarepackages, where an Equation of State (EOS) is previously calibrated to reproduce the saturationpressure value of the studied oil.

In any case, for these types of oils it is advisable to be submitted to a set of experimentalmultistage separator tests.

Viscosimetry -

Determined according to the procedures stated for oils, in section 6.2.

53

Well Head Samples Bottom Hole Samples

Transfer from the sampling cylinder

Determination of thesaturation pressureand of the P-V relation

Selection of the mostrepresentative sample

Separator Determination Constant mass tests of viscosity study

Blow-down at atmospheric pressure

Constant VolumeDepletion study

Chemical analysis andmathematical recombination


Fig. 4Samples of separator oil Samples of separator gas

54










Separator tests Determination Constant Mass study of viscosity

Constant Volume Depletion study Fig. 5

55

6.4 Reservoir fluid: CONDENSATE GAS

General information -

A condensate gas is defined as a mixture of hydrocarbons which, in reservoir conditions, is in agaseous monophase state and which, because of pressure values below its saturation pressure(Dew Point), leads to the formation of a liquid phase.As the depletion progresses, the volume of the condensate retrograde liquid continually increases.As the depletion become deeper and deeper, a partial re-evaporation of condensate componentstakes place along with a consequent reduction in the volume of retrograde liquid.

The GOR values which characterize these fluids are above 700-800 Nm3/m3 approximately (4000-4500 Scf/bbl).

Usually the condensate gases are correctly sampled at the separator.Bottomhole sampling is sometimes carried out.

Fig. 6 shows the procedure for performing a PVT study on reservoir condensate gas obtained byrecombining fluids sampled at the separator.

Controlling the validity of samples -


Chemical composition of reservoir condensate gas -

The composition is determined by analysing the separator liquids and gases according to theprocedures stated in section 4.The composition of reservoir fluid is obtained by calculation, recombininging the separator fluidcompositions according to the separator GOR (measured or calculated from the field GOR).

56

Constant Composition Expansion -

This is the traditional test performed at reservoir pressure to determine the saturation pressure“dew point pressure” of the reservoir fluid, i.e. the pressure at which the first drop of liquidcondenses.

This test is also known as the “Constant Mass Expansion” and as the “Pressure-Volume relation”.

DESCRIPTION -

In a PVT cell fitted with a long windowed area and set to reservoir temperature, a sample of fluid isdepleted by applying a series of thermodynamic equilibria at various pressure steps, with anexperimental determination of the volumes occupied by the mixture in equilibrium conditions.For pressures below saturation or dew point pressure, the volumes of condensed liquid aremeasured using a high precision optical device (cathetometer).

The saturation pressure value is identified by visual inspection and as the discontinuity point onthe “condensed liquid volume - pressure” curve.

REMARKS -

The number of equilibrium pressure steps to apply depends on the reservoir pressure and on thedew point pressure.In most cases, 10 pressure steps are sufficient, four above and six below the Dew Point pressurevalue.

The test is performed on volumes of approximately 300-350 cm3 of reservoir fluid, measured atformation conditions.With the new PVT mercury-free apparatus and suited sampling techniques also 30-40 cm3 ofreservoir fluid sample may be suitable for reliable results.

This test is non destructive and so it may be repeated several times on the same sample.

RESULTS -

57

The parameters below are then calculated from the results of this test and included in the standardPVT report.

- relative volume -This is the ratio between the volume of mixture at the i-th generic equilibrium pressure and thevolume of the same mixture at dew point pressure. This value is adimensional.

- z factor -This is the deviation factor of reservoir gas behaviour in relation to ideal gas behaviour at variousapplied pressures above dew point pressure. The value is adimensional.

- volume of retrograde liquid -This is the volume of condensed liquid at various equilibrium pressures below dew point pressure.The data may be expressed in two different ways.

In the first approach this value is expressed as the volume of retrograde condensed liquid startingfrom 1,000 Nm3 of original gas at saturation pressure. It is expressed in m3 (T&P) / 1,000 Nm3(SC).

In the second approach, this value is expressed as the volume of initial reservoir pore space (madeequal to 100) occupied by the retrograde condensed liquid. This value is expressed as avolumetric percentage.

58

Constant Volume Depletion -

This test is performed at reservoir temperature, in order to simulate depletion in a reservoir whosevolume remains constant. It is known as the CVD test.This test is applied to obtain information on the amount of condensate which remains in thereservoir and on the properties and amount of gases which are produced during depletion.

DESCRIPTION -

A sample of reservoir fluid, obtained by recombining separator fluids in a PVT cell set at constantreservoir temperature, is submitted to a series of equilibrium steps at pre-set and decreasingpressures according to a programme previously defined for the studied gas according to itscharacteristics.At each pressure step above the saturation pressure (Dew Point), the volumes occupied by themonophasic gas mixture in equilibrium conditions are measured.The volume occupied by the gas mixture at reservoir pressure is accurately measured. This value isassumed as the reservoir volume to be kept constant during the subsequent equilibrium steps forsimulating the depletion process.At each pressure step which is lower than saturation pressure (Dew Point), a liquid phase developswhich is in equilibrium with a gas whose properties are different if compared to the originalcondensate gas.The volumes occupied by this liquid and by the entire biphase mixture are measured.Then, at a constant pressure in order to maintain the thermodynamic equilibrium, the initialconstant volume occupied by the original fluid at its reservoir pressure is restored, by removing theexcess part of the equilibrium gas from the cell.This displaceded gas is collected in a special sampling device and the volume, density, z factorand chemical composition are then measured.A sampling device for trapping the heaviest components of the gas is located into a special lowtemperature device.The cycle (expansion at a lower equilibrium pressure, followed by removal of a further amount ofgas) is repeated several times, until a pressure which is sufficiently low to be considered as thereservoir “abandonment pressure” is reached.In this situation, the “gas cap” of the equilibrium is measured, by removing it from the PVT cell.The condensate left is submitted to a flash expansion in the cell, from abandonment pressure toatmospheric pressure. The volumes of the gas which is released and the residual condensateliquid are measured and the density and chemical composition are determined.

59

REMARKS -

It is advisable to apply the first equilibrium at a pressure very close to saturation pressure (about15-20 Kg/cm2 or 200-300 psi below the Dew Point) in order to evaluate even the small amounts ofretrograde liquid which form in the reservoir.In relation to the high saturation pressure value and the large volume of condensable liquid at least8-10 different equilibria pressure steps need to be applied in order to get a better simulation of thedepletion process of these fluids.The abandonment pressure is chosen freely and usually ranges from 30 to 50 Kg/cm2 (450 - 700psi), but may also be atmospheric pressure.The mass and composition of the test are variable, so it is a destructive type test.It cannot be repeated, unless a new volume of whole sample is used.The test is performed with 300-350 cm3 of monophase reservoir fluid.

In order to correctly and accurately perform this test, a PVT cell equipped with a window which issufficiently long to enable liquid volumes to be detected and measured at each equilibrium isneeded.In order to ensure accurate results, the best labs perform a global mass balance and a molecularmass balance of each component as a control, to verify that the initial quantity of the hydrocarbonshas been recovered both as gas and as residual condensate liquid.

RESULTS -


volume of retrograde liquid -This is the volume of condensed liquid at various equilibrium pressures below dew point pressure.The data may be expressed in two different ways.In the first approach this value is expressed as the volume of condensed liquid starting from 1,000Nm3 of original gas at saturation pressure. It is expressed in m3 (T&P) / 1,000 Nm3 (SC).In the second approach, this value is expressed as the volume of initial reservoir pore space (madeequal to 100) occupied by the condensed liquid. This value is expressed as a volumetricpercentage.

- cumulative gas produced -This is the amount of cumulative gas produced during the reservoir’s depletion. It is expressed inNm3 of gas from each 1,000 Nm3 of initial equivalent gas at saturation pressure (or from each1,000 Nm3 of initial equivalent gas at initial reservoir pressure).

- z compressibility factor of the gas produced -This is the deviation factor of equilibrium gas behaviour in relation to ideal gas behaviour. Thevalue is adimensional.

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- chemical composition of gas -This is the composition of each gas produced and in equilibrium with the condensed liquid atreservoir temperature formed during the test. It is expressed as a molar % for each singlecomponent.

- potential liquid products -These are the liquid volumes which could be produced at the surface by each type of gasproduced. These products are calculated on the basis of the chemical composition of gas and areexpressed in m3 of liquid at 15 °C for reach 1,000 Nm3 of gas produced.

- cumulative potential liquid products -These are the cumulative liquid volumes which could be produced at the surface in relation to eachdepletion level of the reservoir, starting from a pre-set amount (volume) of reservoir fluid atsaturation pressure (dew point) or at reservoir pressure. These products are calculated andexpressed in m3 of liquid at 15°C from each 1,000 Nm3 of initial equivalent gas at saturationpressure or from each 1000 Nm3 of initial equivalent gas at reservoir pressure.

All these results are given in the PVT Report both as tables and as graphs

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Separator tests -

As a general rule, these are not required. A standard PVT Report usually provides the resultsobtained from a thermodynamic simulator, by calculating the flash equilibrium at selectedseparation conditions.

For these types of fluids it may be advisable a set of multistage separator tests to be carried out.

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Samples of separator oil Samples of separator gas










Constant Mass study

Constant Volume Depletion study Fig. 6