Pvt Best Practices

PVT BEST PRACTICES

PVT Sampling Constant Composition Expansion

Density

GAS

Constant Volume Depletion

OIL Differential Vaporization

Viscosity

1

INTRODUCTION This Manual was prepared to provide suitable guidelines to deal with PVT activities in order to obtain the best results in each situation. The experience of our technicians involved in PVT studies was used with the final goal to offer a user friendly Manual to any Department or Subsidiary which has to deal with the studies 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 a practical 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 to improve and keep updated future versions of this Manual.

G. P.

2

PVT BEST PRACTICE CONTENTS

Pg.

1.

QUALITY OF THE LABS

3

1.1.

General information

4

2.

RESERVOIR FLUIDS SAMPLING

5

2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8

Aim Well conditioning Method When and how much to sample Documents Sampling containers Field controls Suggestions

6 7 8 10 11 13 14 15

3.

CONTROLLING THE VALIDITY OF SAMPLES

16

3.1

General information

17

4.

CHEMICAL COMPOSITION OF RESERVOIR FLUIDS

18

4.1 4.2 4.3 4.4 4.5 4.6

Pressurised liquids H2S in pressurised liquid samples Pressurised gas H2S in pressurised gas samples CO2 in pressurised gas samples Stock-tank liquids

19 20 21 22 23 24

5.

PRELIMINARY TESTS AND RECOMBINATIONS

29

5.1

General information

30

6.

REQUESTING A PVT STUDY

31

6.1 6.2 6.3 6.4

Reservoir fluid: DRY GAS Reservoir fluid: OIL Reservoir fluid: VOLATILE OIL Reservoir fluid: CONDENSATE GAS

32 36 48 55

3

1. QUALITY OF THE LABS

4 1.1

GENERAL INFORMATION

The study of reservoir fluids provides the reservoir engineer with fundamentally important data. For this reason these studies must be handled by qualified PVT labs, which are able to ensure high quality results. The use of established analytical procedures, as well as reliable techniques for data evaluation and precision 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 widest range possible of temperatures and operating pressures. Usually, each item of equipment is purposely designed and developed to provide an optimal performance 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 on reservoir 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 pumps which work with mercury and mercury-free systems. The most updated apparatus can work computer assisted.

5

2. RESERVOIR FLUIDS SAMPLING

6 2.1

AIM

The aim of sampling is to collect a sample which is representative of the reservoir fluid at the time of sampling. Sampling must be considered just as important as subsequent lab analyses, in order to ensure 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 on whether (or not) the tested sample is representative of fluid in the reservoir or at least in the drained area of the well. The sample may not be the true “average” fluid of the whole reservoir and so the results may have to be slightly adjusted successively. In any case, the quality of a PVT study and subsequent engineering calculations which are based on data of the study cannot be better than the quality of the fluid samples originally collected during the sampling. A good PVT report must include accurate comments on the validity of the samples used for the study. It is therefore advisable to carefully read the comments attached to PVT reports.

7 2.2

WELL CONDITIONING

One of the most important factors for obtaining representative samples is adequate well conditioning before sampling. The “API Recommended Practice for Sampling Petroleum Reservoir Fluids” of the American Petroleum Institute (API RP 44, January 1966), fully describes the recommended conditioning techniques and different sampling methods.

The aim of well conditioning is to remove non-representative reservoir fluid present around the well, by displacing it with original fluid which comes from the furthest part of the reservoir. Well conditioning basically involves managing the well’s flow rates, controlling and recording the production trend for as long as possible before sampling and gradually reducing the well’s flow rate in 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 with varying well flow rates. The validity of PVT analysis depends on the accuracy of the GOR value used to recombine the separator gas and oil samples. When the GOR is not perfectly stable during sampling, but fluctuates, the recombination GOR must be 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 slightly undersaturated fluids and in condensate gas reservoirs.

8 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 PVT analysis: - bottom hole sampling - well head sampling - surface sampling.

The choice of which method to adopt basically depends on the type of reservoir fluid and on 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 and then physically recombine them in the lab, according to the volumetric gas/oil ratio (GOR) of the separator. In the case of condensate gas reservoirs, irrespective of whether they are saturated or undersaturated, it is recommended to collect samples at the separator. Suitable well conditioning and correct sampling techniques at the separator are particularly important for these types of fluids and 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, low viscosity liquids and this can be done using water as the displacement fluid instead of mercury, or cylinders which are fitted inside with a piston or membrane. When cylindrical containers fitted with a mobile (floating) piston are used, the sampling procedure stated in the “Standard Practice for Containing Hydrocarbon Fluid Samples Using a Floating Piston Cylinder” (ASTM D 3700-78) should be adopted. This standard is the exact equivalent of the specification “GPA Standard 2174” which is suggested for sampling natural gases using the same type of sampling container.

9

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 the standard “Methods for Obtaining Natural Gas Samples for Analysis by Gas Chromatography” (GPA Standard 2166, 1986). Other reference standards include: - “Standard Method of Sampling Natural Gas (ASTM D 1145 - 1980) - “Sampling Manual ISO 3170”

10 2.4

WHEN AND HOW MUCH TO SAMPLE

It is suggested to collect samples immediately at the beginning of the reservoir’s life, preferably after a few weeks of production, so that original virgin reservoir fluid can be obtained before the formation 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 600 cm3 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 for performing a complete PVT study (1 litre for the oil studies and 0.5 litres for the condensate gas studies).

If separator pressure is very low (less than 10 kg/cm2) and the GOR is higher than 300 Nm3/m3, it is 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 one and includes multistage separator tests, swelling tests or miscible displacement tests, the volume of samples to be collected must be agreed on beforehand with lab experts.

11 2.5

DOCUMENTS

It is to be pointed out that the documents containing the sampling data must accompany the samples and that the Production Test Report must be sent to the PVT lab appointed to carry out the study. The information included in these documents is used to check the validity of samples, make comparisons between field test data and lab test data, and obtain reliable data for the accurate recombination of separator gas and liquid samples. In all cases, documents containing sampling data and the production test report should be attached to the PVT works programme.

During sampling, the reservoir and test parameters listed below must be measured and recorded on 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 1 st 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 mercury or water, whether H2S and/or CO2 are present, etc.

In the case of bottomhole sampling, the flowing pressure at the sampling depth is extremely important and must be significantly lower than the saturation pressure of the sampled fluid, at reservoir 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 requesting and checking that the measurement tools which are used, conform to standards and have been properly calibrated.

12 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 rates using a turbine-flowmeter: - “ANSI Publication 2101 (1981)”.

13 2.6

SAMPLING CONTAINERS

Pressurised samples must be collected in steel containers, usually cylindrical, with or without an internal moving piston, correctly designed to support high pressures and these must be accurately packed 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 of materials and technical performance at working pressures.

It should be noted that cylinders for sampling pressurised hydrocarbons must comply with national and international standards on transport. For example, in the USA, the “Hazardous Materials Regulations of the Department of Transportation” and in Italy the regulations issued by the Ministry of 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 IMDG regulations in the event of sea transport.

In the case of sampling pressurised fluids which contain H2S, it is possible to use teflon-lined cylinders 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 special declaration and shipping cautions are requested.

14 2.7

FIELD CONTROLS

In the case of bottomhole sampling, some simple field tests can be performed to check whether or not 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 step procedure to pressurize the sample progressively. The relation between the injection pressure and the cumulative volume of injected fluid can be used to 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 the same measured properties, it is highly likely that representative and reliable samples have been collected.

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

15 2.8

SUGGESTIONS

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

Bottomhole sampling should be carried out with the well flowing through the smallest choke possible. This makes it possible to keep the pressure “drawdown” at minimum, the flowing pressure 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 are slightly undersaturated), if a well is particularly important in strategic-economic terms, and if sampling repetition does not seem possible in the future, it is suggested to perform both bottomhole 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 better understanding of the real reservoir fluid.

16 3. CONTROLLING THE VALIDITY OF SAMPLES

17 3.1

GENERAL INFORMATION

As the representativeness of a PVT study depends a great deal on sampling conditions, the first and most important action, before proceeding with the complete reservoir fluid study, is to check the validity of samples. In all cases, each sample, whether collected bottomhole, at well head, or at the separator must be controlled to check its validity. The reciprocal consistency of a set of samples collected in similar conditions is checked as follows: - in the case of bottomhole liquid (BHS) or well head (WHS) samples, by determining the saturation pressures at ambient temperature, and in extreme cases, at reservoir temperature. The results are then compared to reservoir static pressure and flowing pressure values. If the saturation pressures of at least two samples are similar to each other, with a reciprocal deviation below 2%, and if these saturation pressures are below reservoir pressure and flowing pressure values, the samples may be considered as reliable and representative of reservoir fluid. 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 all samples are unreliable. This problem is handled by PVT and reservoir experts and is solved case by case. - in the case of separator liquid samples by determining their saturation pressures at separator temperature. Their saturation pressure must coincide with separator pressure value. - in the case of separator gas samples by determining the cylinder opening pressure, the air content and chemical composition of the gas mixture. Prior to this, the cylinder must be heated to a temperature above the separator temperature 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 be strictly identical each other.

In the case of volatile oils, due to their extremely elastic behaviour, it is advisable to request 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 tests must be carried out by determining the Dew Point of each sample in a windowed cell at reservoir temperature. The samples will be consistent if they have the same Dew Point and are valid if the Dew Point is lower than the reservoir pressure value.

18 4. CHEMICAL COMPOSITION OF RESERVOIR FLUIDS

19

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 two stabilised 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 by distillation (mini-Podbielniak, Fisher or other methods) and gas chromatography respectively, using the techniques mentioned in the next sections. These compositions are usually determined up to the fraction C13 plus for liquid and up to the fraction 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 the volumetric ratio of the two phases (GOR) measured during the test, in order to obtain the calculated composition 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 the error inherent to measuring the volumetric ratio (GOR) is fairly small. This technique is less accurate for rich gas mixtures (condensate gas), where the volume of condensate 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 condensable components and these should be agreed on with the PVT lab in order to obtain the most accurate information on the percentages of the heavier components present in the mixture.

20 4.2

H2S IN PRESSURISED LIQUID SAMPLES

When hydrogen sulphide is present in pressurised liquid samples, it is advisable to check that the sample 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 (blowdown method) and the percentage of H2S present in the released gas must be immediately measured 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 the concentration of H2S in the original pressurised liquid. If it is not possible to use teflon-lined cylinders, we suggest carrying out this measurement as quickly as possible after the sample has been collected, to avoid the consumption of H2S caused by its reaction with the steel of the cylinders.

21 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 IP 354 standards; the chromatograph may be modified with capillary columns to improve its performance. 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 which extend 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 gas analysis: - GPA Standard 2261 - 90 - ASTM D 1945 - ISO 6974

It is advisable to request the chemical gas composition to be determined immediately on site at 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 could chemically react with the material (steel) of the sampling container and/or with other components present in the gas mixture (CO2, H2O vapour).

22 4.4

H2S IN PRESSURISED GAS SAMPLES

Hydrogen sulphide in the gaseous phase should preferably be directly determined on site at the field as this component is absorbed in different degrees by the metal surface of the containers used for sampling. The measurement technique used to determine the amounts of H2S depends on the value of the H2S 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 H2S concentrations 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 from mercaptans. 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 cadmium sulphate to adsorb the H2S and the third containing a mixture of cadmium sulphate and hydroxide to 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 for Determination of Hydrogen Sulphide and Mercaptan Sulphur in Natural Gas (Cadmium Sulphate Iodometric 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.

23 4.5

CO2 IN PRESSURISED GAS SAMPLES

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

gas

- The Draeger tubeThis is an adsorption method for the quick determination of a wide range of concentrations, though values are approximate.

- Orsat (UOP 172) This is a simple, chemical method, which can be used with precision only for CO2 concentrations above 0.2%; a known volume of gas is put in contact with a solution of sodium hydroxide that reacts with the CO2, subtracting it from the gaseous phase; the CO2 concentration is then determined according to the reduction in the gas volume.

24 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 with international 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 - even up to C25 plus and/or C30 plus components - can be performed, by distilling at temperatures of 350°C and using capillary column equipment. The packed columns are easier to be used than capillary ones, but the latter produce closer peaks which make it possible to identify a greater number of single components and so they are more selective.

The overall results are expressed as weight %, then converted to molar %, for single components up 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 (“True Boiling Point Distillation”) with 15 theoretical plates.

- ASTM D 1160 Strong vacuum distillation, but up to 400°C, corresponding to the UOP 109 standard, which makes it possible to extend the analysis beyond the C20s.

- ASTM D 158 Saybolt distillation, up to 350°C.

- ASTM D 216 -

25

Engler distillation, suitable for extremely volatile liquids.

- ASTM D 285 Hempel distillation, equivalent to the UOP 77 standard, but which characterises liquids cuts by distillation 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 composition of the fluids analysed.

to determine the chemical

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

26

STOCK-TANK OIL

DISTILLATION

LIGHT FRACTION

INTERMEDIATE FRACTION

GC ANALYSIS

CAPILLARY GC ANALYSIS

MOLAR COMPOSITION

MOLAR COMPOSITION

RESIDUE

MEASUREMENTS OF: SPECIFIC WEIGHT MOLECULAR WEIGHT

RECOMBINATION

MOLAR COMPOSITION OF STOCK-TANK OIL

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

27 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, aromatic and naphthenic compounds.

- fingerprint analysis this is a gas chromatographic technique where liquid hydrocarbons can be compared by simple visual examination of the raw chromatogram, without having to identify the single components and determine 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, the cloud point is determined instead using non-standard methods such as “differential scanning calorimetry (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 by precipitating the waxes at a temperature of - 30°C, after having removed all the asphaltenes present (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 & Stark equipment, with a good rate of precision, widely used for liquids with a water content of more than 0.5% in volume; ASTM D 4377, IP 356, based on Karl-Fischer potentiometric titration. These standards are advised for water concentrations below 0.5% in volume; FINA Aquatest, a simple, quick method which is less accurate than the others and can be used mainly for field measurements on site.

-BS&WThe 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

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

It should be noted that the terminology and definitions concerning the various types of water 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 to the IP 71 method and the ISO 3104 standard and valid for hydrocarbons mixtures of Newtonian rheological behaviour. The time needed for a given liquid volume to flow through a calibrated capillary viscosimeter under the 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 capillary viscosimeter used. The dynamic viscosity, expressed in centipoises, is obtained by multiplying the kinematic viscosity by 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 the standard 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.

29 5. PRELIMINARY TESTS AND RECOMBINATIONS

30 5.1

GENERAL INFORMATION

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 this factor is always less than 1 and depends on the type of oil; usually for each type of oil this value decreases as the separator pressure increases. - measuring the density of the separator oil under separator conditions. For this purpose, use of an Anton Paar densimeter is suggested.

The physical recombination of separator fluids involves creating a significant volume of reservoir fluid 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 and independent 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 a preliminary “GOR - Saturation Pressure” study, where several separate recombinations using different GOR values are performed and the saturation pressure value of each mixture is determined. A study of the results, compared to reservoir conditions, can clarify which is the true fluid 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)

31 6. REQUESTING A PVT STUDY

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

Dry gases Oils (heavy, medium, light) Volatile oils Condensate gas

32 6.1

Reservoir fluid: DRY GAS

General information Dry gas is defined as a mixture of hydrocarbons (usually natural gas) with a chemical composition which 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 wet gas.

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 into account 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.

33 Compressibility factor (z) of reservoir gas This determination is the most important for characterising the volumetric behaviour of gas and must be carried out at reservoir temperature (Tg). The z factor, also known as the “gas deviation factor” is determined within a range of pressures from reservoir pressure to atmospheric pressure. The volume taken up by the gas at reservoir temperature and many pressures (at least six different ones) is measured, in conditions of thermodynamic equilibria, in a PVT cell fitted with an observation window. The gas is then displaced from the cell and collected in a volume measuring device at atmospheric pressure 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 Vi z = --------------------- * -------------Tg * Pstandard Vstandard

Note that Tstandard = 273 + 15 = 288 °K = 60 °F Pstandard = 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 reservoir temperature. It may also be important to know the z value of a dry gas at temperatures other than reservoir temperature. In these cases it is advisable to ask the PVT lab to determine the z factor, even at temperatures of specific interest. Measuring the z value is advisable, especially for gases containing non-hydrocarbon products such as CO2, H2S, N2 which change the real gas behaviour a great deal if compared to the ideal gas and therefore make the theoretical methods for determining z values less reliable. The observation window is used to check whether any amounts, even minimum, of condensed products, 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 an Anton Paar densimeter. The density of the same gas at atmospheric conditions is usually calculated on the basis of the chemical composition.

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

Potential liquid products These are defined as “the volumetric amount (m3 at 15 °C) of liquid which could be produced by 1 Million Nm3 of initial gas at reservoir pressure, if it were possible to liquefy all the hydrocarbon components, from C3 to the heaviest (C3 plus), from C4 to the heaviest C4 plus), from C5 to the heaviest (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 MOST REPRESENTATIVE SAMPLE

EXPERIMENTAL DENSITY

EXPERIMENTAL Z FACTOR

CALCULATED GAS DENSITY

CALCULATED GAS 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, at pressures below the saturation pressure (bubble point) give rise to a continual and cumulative shrinkage 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 gas dissolved 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 medium oils light oils

0 < GOR < 50 Nm3/m3 51 < GOR < 200 Nm3/m3 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 according to different procedures. Fig. 2 shows the procedure for performing a PVT study on reservoir oil samples collected from the bottom hole or at the well head. Fig. 3 shows the procedure for performing a PVT study on reservoir oil obtained by recombining the fluids sampled at the separator.

Validity check of samples According to the procedures stated in section 3.

Chemical composition of reservoir oil Determined according to the procedures stated in section 4.

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 is released 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 to depletion; this involves applying a series of thermodynamic equilibria at various pressure steps and experimentally 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 and constant composition expansion. The saturation pressure value is identified by visual inspection and by the point of discontinuity on the “pressure-volume” curve. REMARKS The number of equilibrium pressures (steps) to be investigated depends on reservoir pressure and 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 PVT mercury-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 PVT Report : Relative Volume This is the ratio between the volume of the mixture at the i-th general equilibrium pressure and the volume 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 saturation pressure. The compressibility of oils is greater when the oils are light, the temperature higher and the pressure lower. The unit of measurement is m3/(m3 x MPa), or in other words 1/MPa.

the Y function This is an adimensional parameter defined by the ratio P sat - Pi ----------------Psat Y = --------------------------------Vi - Vsat ----------------Vsat This parameter represents the deviation percentage of pressures in relation to the deviation percentage of volumes, compared to saturation conditions, for each generic equilibrium pressure Pi. The parameter is only calculated for pressures values below saturation pressure, and so only in the biphase range. In this field, the experimental volumetric data, if corrected, must produce Y calculated values which must lie on a straight line, when plotted on a graph as a function of pressure,: 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 during reservoir depletion from initial pressure to atmospheric pressure. In the case of heavy, medium and light oils (black oils) it is worldwide acknowledged that differential vaporisation is the process which satisfactorily approximates the phenomena which occur in the reservoir during its depletion.

DESCRIPTION A reservoir fluid sample, previously transferred in a windowed PVT cell at constant reservoir temperature, is submitted to a series of equilibria steps at different pressure values, which gradually decrease according to a programme previously scheduled according to the characteristics of the oil to be tested. The volumes assumed by the mixture at equilibrium conditions are measured at each pressure step. At each pressure value lower than the saturation pressure of the original oil, a gas phase develops which is in equilibrium with a liquid whose properties are different if compared to those of the original oil. All the gas which has been released is therefore transferred outside the cell, at constant pressure to 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 to atmospheric pressure, thus producing degassed residual oil. The residual oil is measured and recovered in order to determine the specific weight at atmospheric 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 is determined 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 6-7 pressure steps below the bubble point, while oils with a low bubble point (up to 50 Kg/cm2, about 700 psi) only need 3-4 pressure steps. The mass and composition of the mixture are variable during the test execution and so this type of test 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 of reservoir fluid sample may be suitable for reliable results. In order to ensure accurate results, the best labs perform a global mass balance and a molecular mass balance of each component as a control, to verify that the initial quantity of hydrocarbons has been 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 included in 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 Rs and 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 and the volume of residual oil at standard conditions. It is indicated by the symbol O.R.V.F. or Bo, and expressed 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 reservoir temperature and at any given pressure, and the volume of residual oil at standard conditions. It is indicated 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 as Kg / m3 (T&P). - gas density This is the density of equilibrium gases, determined at 15°C and at atmospheric pressure, relative to 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. The value is adimensional. - gas volume factor This is the ratio between the volume occupied by a given mass of gas in equilibrium conditions at reservoir temperature and at any given pressure and the volume occupied by the same mass of gas 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 the test. 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 determine the separator pressure value which can ensure maximum recovery of stock-tank oil (degassed) at a pre-defined separation temperature. At the same time, the volumetric coefficient which quantifies the maximum recovery compared to oil available in the reservoir is determined. DESCRIPTION A measured volume of a sample of the reservoir oil is removed from a PVT cell at constant pressure and in monophase conditions and is suddenly expanded (flash test), through a valve in a windowed container (separator) which is kept at a constant separation temperature and previously pressurised with inert gas to the chosen operating pressure. The reservoir oil which is injected into the separator produces a gas and a liquid (separator gas and oil), which are assumed to reach a condition of thermodynamic equilibrium at separation conditions. During the test, in order to maintain a constant separation pressure, the gas is continually removed from the top of the container, allowing it to flow into a sampling equipment which is suitable for determining the volume, density and chemical composition. The separator oil is then depressurised until it reaches atmospheric pressure, with an additional volume 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 to happen 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 50 Kg/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 a more 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 tests requires about 200 cm3 of fluid.

Multistage separator tests may also be requested, which means that the separation process takes 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 may probably be designed, in order to maximise the production of condensates. Each separation stage takes place at temperatures and pressures which are constant yet different from those of other stages. There is no standard lab equipment suitable for these tests. Usually the tests are carried out by assembling in cascade a series of PVT cells for the high pressure separation stages, with traditional separators for the remaining low pressure stages. RESULTS The parameters below are then calculated from the results of this test and included in the standard PVT Report.

- oil formation volume factor This is the ratio between the volume of oil available at reservoir temperature and at bubble point pressure and the volume of stock-tank oil which could be produced through a separation system operating at the indicated separation temperature and pressure. It is indicated by the symbol O.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 and pressure, and the volume of the resulting stock-tank oil at standard conditions. It is indicated by the symbol 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 the reservoir 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 under atmospheric pressure by the separator oil and the volume of stock-tank oil produced and associated 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 the separation 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 reservoir temperature and at a range of pressures values between the original reservoir pressure and atmospheric pressure. For pressures values above the saturation pressure of the reservoir oil, the viscosity of the integral original oil is measured. For pressures values below the saturation pressure of the reservoir oil, the viscosity of the equilibrium liquid phase produced during a step-by-step differential process vaporisation is measured.

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

REMARKS This measuring system is valid for all liquid hydrocarbon mixtures which show a Newtonian rheological behaviour in measurement conditions. It is not possible to take accurate measurements on reservoir oils which have an emulsified water content of more than 1% in weight. The viscosities of gases in equilibrium conditions are calculated on the basis of their chemical composition. The viscosity tests are particularly important for medium and heavy oils, with a viscosity above 30 cP. 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 determined in 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 ball d2 = the density of reservoir oil at the measurement pressure k = the calibration constant of the measurement tool t = the measured time u = 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 the saturation pressure and of the P-V relation

Selection of the most representative sample

Separator tests

Determination of viscosity

Constant mass study Blow-down at atmospheric pressure

Differential Vaporization study

Chemical analysis and mathematical recombination

Composition of reservoir fluid

Fig. 2

47 Samples of separator oil

Samples of separator gas

Determination of saturation pressure

Gas chromatographic analyses

Selection of the most representative sample

Blow-down at atmospheric pressure

Composition of separator gas

Chemical analysis and mathematical recombination

Selection of the most representative sample

Composition of separator oil

Mathematical recombination of compositions of separator fluids

Composition of reservoir fluid

Physical recombination of samples

Recombined sample of reservoir fluid

Separator tests

Determination of viscosity

Constant Mass study

Differential Vaporization study

6.3

Reservoir fluid: VOLATILE OIL

Fig. 3

48

General information Volatile oil is defined as a mixture of hydrocarbons with the same behaviour as that of “oils”, but characterised 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 saturation pressure 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 oils undergo ”constant volume depletion” rather than conventional differential vaporisation as the former 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 bottom hole or well head sampling. Fig. 5 shows the procedure for conducting a PVT study on volatile reservoir oil obtained by recombining the fluids sampled at the separator.

Validity check of samples According to the procedures stated in section 3.

Chemical composition of reservoir oil Determined according to the procedures stated in section 4.

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 reservoir whose 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 reservoir and 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 to constant reservoir temperature, is submitted to a series of equilibrium steps, at pre-set and decreasing pressures, according to a programme previously defined for the studied oil’s characteristics. At each pressure step which is above oil saturation pressure, the volume occupied by the monophase mixture in equilibrium conditions is measured. At the saturation pressure of the original oil, the volume occupied by the mixture is accurately measured and this value is assumed as the reservoir volume to be kept constant during the subsequent equilibrium steps devoted to simulate the depletion process. At each pressure step which is lower than the saturation pressure of the original oil, a gaseous phase develops which is in equilibrium with a liquid oil phase whose properties are different if compared 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 constant volume occupied by the original fluid at its saturation pressure is restored, by removing the excess part of the equilibrium gas from the cell. This displaced gas is collected in a special sampling device and the volume, density, z factor and chemical composition are then measured. The cycle (expansion at a lower equilibrium pressure, followed by removal of the released gas to restore the constant volume) is repeated several times, until a pressure which is sufficiently low to be considered as the reservoir “abandonment pressure” is reached. In this situation, the gas cap in equilibrium conditions is measured, by removing it from the PVT cell. The remaining oil undergoes a flash test in a cell, from abandonment pressure to atmospheric pressure. The volume of the released gas and residual oil are measured and the density and chemical composition are determined.

50 REMARKS Given the large amounts of gas released, even just below saturation pressure, and the consequent high volumetric oil shrinkage, which is characteristic of these types of fluids, it is advisable to apply the first equilibrium at a pressure very close to saturation pressure (about 8-10 Kg/cm2 below B.P.). In relation to the high saturation pressure value and the large volume of dissolved gas at least 8-10 different equilibrium pressure steps need to be applied in order to better describe the depletion process of these oils. The abandonment pressure is chosen freely and usually ranges from 30 to 50 Kg/cm2 (450 to 750 psi). 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 of reservoir fluid may be suitable for reliable results. In order to correctly and accurately perform this test, a PVT cell fitted with a window which is sufficiently 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 molecular mass balance of each component so that the initial load of the hydrocarbons is recovered both as gas and as residual oil.

RESULTS The parameters below are then calculated from the results of this test and included in the standard PVT Report. - reservoir oil shrinkage factor This is the ratio between the volume of oil at each equilibrium pressure and the volume of original oil at saturation pressure. It expresses the entity of the reservoir oil shrinkage factor below saturation 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 in Nm3 of gas for each 1,000 Nm3 of initial equivalent gas at saturation pressure. It may also be expressed 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. The value is adimensional.

51 - gas volume factor This is the ratio between the volume occupied by an equilibrium gas mass at reservoir temperature and 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 the test. 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 gas produced. These products are calculated on the basis of the chemical composition of the gas and are 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 each depletion level of the reservoir, starting from a determined amount (volume) of reservoir fluid at saturation pressure. These products are evaluated theoretically by calculation and expressed in m3 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 also be calculated. However, it is not a standard routine of all labs to include these data in the PVT Report 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 thermodynamic equilibrium of a flash process; these calculations are performed with suitable PVT software packages, where an Equation of State (EOS) is previously calibrated to reproduce the saturation pressure value of the studied oil. In any case, for these types of oils it is advisable to be submitted to a set of experimental multistage 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 the saturation pressure and of the P-V relation

Selection of the most representative sample

Separator tests

Determination of viscosity

Constant mass study Blow-down at atmospheric pressure

Constant Volume Depletion study

Chemical analysis and mathematical recombination

Composition of reservoir fluid

Fig. 4 Samples of separator oil

Samples of separator gas

54

Determination of saturation pressure

Selection of the most representative sample

Gas chromatographic analyses

Blow-down at atmospheric pressure

Composition of separator gas

Chemical analysis and mathematical recombination

Selection of the most representative sample

Composition of separator oil

Mathematical recombination of compositions of separator fluids

Composition of reservoir fluid

Physical recombination of samples

Recombined sample of reservoir fluid

Separator tests

Determination of viscosity

Constant Mass study

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 a gaseous 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 components takes 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 (40004500 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 by recombining fluids sampled at the separator.

Controlling the validity of samples According to the procedures stated in section 3.

Chemical composition of reservoir condensate gas The composition is determined by analysing the separator liquids and gases according to the procedures stated in section 4. The composition of reservoir fluid is obtained by calculation, recombininging the separator fluid compositions 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 liquid condenses. 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 is depleted by applying a series of thermodynamic equilibria at various pressure steps, with an experimental determination of the volumes occupied by the mixture in equilibrium conditions. For pressures below saturation or dew point pressure, the volumes of condensed liquid are measured using a high precision optical device (cathetometer). The saturation pressure value is identified by visual inspection and as the discontinuity point on the “condensed liquid volume - pressure” curve.

REMARKS The number of equilibrium pressure steps to apply depends on the reservoir pressure and on the dew point pressure. In most cases, 10 pressure steps are sufficient, four above and six below the Dew Point pressure value. The test is performed on volumes of approximately 300-350 cm3 of reservoir fluid, measured at formation conditions. With the new PVT mercury-free apparatus and suited sampling techniques also 30-40 cm3 of reservoir 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 standard PVT report.

- relative volume This is the ratio between the volume of mixture at the i-th generic equilibrium pressure and the volume 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 various applied 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 starting from 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 (made equal to 100) occupied by the retrograde condensed liquid. This value is expressed as a volumetric percentage.

58 Constant Volume Depletion This test is performed at reservoir temperature, in order to simulate depletion in a reservoir whose volume remains constant. It is known as the CVD test. This test is applied to obtain information on the amount of condensate which remains in the reservoir 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 constant reservoir temperature, is submitted to a series of equilibrium steps at pre-set and decreasing pressures according to a programme previously defined for the studied gas according to its characteristics. At each pressure step above the saturation pressure (Dew Point), the volumes occupied by the monophasic gas mixture in equilibrium conditions are measured. The volume occupied by the gas mixture at reservoir pressure is accurately measured. This value is assumed as the reservoir volume to be kept constant during the subsequent equilibrium steps for simulating the depletion process. At each pressure step which is lower than saturation pressure (Dew Point), a liquid phase develops which is in equilibrium with a gas whose properties are different if compared to the original condensate 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 initial constant volume occupied by the original fluid at its reservoir pressure is restored, by removing the excess part of the equilibrium gas from the cell. This displaceded gas is collected in a special sampling device and the volume, density, z factor and chemical composition are then measured. A sampling device for trapping the heaviest components of the gas is located into a special low temperature device. The cycle (expansion at a lower equilibrium pressure, followed by removal of a further amount of gas) is repeated several times, until a pressure which is sufficiently low to be considered as the reservoir “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 to atmospheric pressure. The volumes of the gas which is released and the residual condensate liquid 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 (about 15-20 Kg/cm2 or 200-300 psi below the Dew Point) in order to evaluate even the small amounts of retrograde liquid which form in the reservoir. In relation to the high saturation pressure value and the large volume of condensable liquid at least 8-10 different equilibria pressure steps need to be applied in order to get a better simulation of the depletion process of these fluids. The abandonment pressure is chosen freely and usually ranges from 30 to 50 Kg/cm2 (450 - 700 psi), 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 is sufficiently long to enable liquid volumes to be detected and measured at each equilibrium is needed. In order to ensure accurate results, the best labs perform a global mass balance and a molecular mass balance of each component as a control, to verify that the initial quantity of the hydrocarbons has been recovered both as gas and as residual condensate liquid.

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

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 1,000 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 (made equal to 100) occupied by the condensed liquid. This value is expressed as a volumetric percentage.

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

60 - chemical composition of gas This is the composition of each gas produced and in equilibrium with the condensed liquid at reservoir temperature formed during the test. 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 by each type of gas produced. These products are calculated on the basis of the chemical composition of gas and are expressed 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 each depletion level of the reservoir, starting from a pre-set amount (volume) of reservoir fluid at saturation pressure (dew point) or at reservoir pressure. These products are calculated and expressed in m3 of liquid at 15°C from each 1,000 Nm3 of initial equivalent gas at saturation pressure 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

61 Separator tests -

As a general rule, these are not required. A standard PVT Report usually provides the results obtained from a thermodynamic simulator, by calculating the flash equilibrium at selected separation conditions. For these types of fluids it may be advisable a set of multistage separator tests to be carried out.

62

Samples of separator oil

Samples of separator gas

Determination of saturation pressure

Gas chromatographic analyses

Selection of the most representative sample

Blow-down at atmospheric pressure

Composition of separator gas

Chemical analysis and mathematical recombination

Selection of the most representative sample

Composition of separator oil

Mathematical recombination of compositions of separator fluids

Composition of reservoir fluid

Physical recombination of samples

Recombined sample of reservoir fluid

Constant Mass study

Constant Volume Depletion study

Fig. 6