002.0 Surface Sampling Training

Surface Sampling Training Section

This training section is divided into the following topics:

Surface sampling overview Sampling the separator gas phase Sampling the separator liquid phase Possible problems encountered during surface sampling Quality control of the separator gas and liquid streams References

Surface Sampling overview The well should be conditioned as described before and the flow stability should be perfect before surface sampling is attempted while the system is producing at the lowest possible flow rate. Flowing stability can be checked by the following criteria: o stabilised surface gas and oil flow rates o stabilised well head pressure o stabilised flowing bottom hole pressure Pwf When multistage separation is used, both samples should be taken from the highest pressure separator. Samples may be taken as soon as it has been determined that the well is properly conditioned and the flow stabilised.

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Gas Gas meter W ell

Separator

Gas sample Oil

W ater

Stock tank Oil sample

W ater sample

Surface Sampling Oil & Gas

As described earlier, representative surface sampling of gas condensate wells requires a minimum velocity to lift all condensed fluids in the wellbore. The gas and liquid samples should be taken at essentially the same time. The difference in time should be as small as possible because significant changes in separation conditions, particularly the temperature, can occur with time. The need to obtain accurate values for the gas and oil flowrates prevailing at the time of sampling can not be overemphasised. The PVT laboratory has to rely on the reported GOR for the physical recombination. Inaccurate field flow rates applied to perfectly valid surface samples will clearly lead to an invalid recombined fluid. Example: A volatile oil from Africa produced from a reservoir at 214OF was sampled at separator pressure of 168 psia and temperature of 78OF. The reported field GOR was 1200 scf/sbbl. If we assume that the gas-to-oil ratio has been underestimated by 5% (actual GOR =1260 scf/sbbl) then simulation runs show that the two recombined fluids will exhibit the following differences:

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Bubble Point Pressure Reservoir oil density @ Pb Gas Z factor @ Pb Total GOR from sep test Oil Volume Factor

Fluid with GOR=1200scf/sbbl

Fluid with GOR=1260 scf/sbbl

2936 psia

3017 psia

0.574 g/cm3

0.563 g/cm3

0.831

0.829

1512 scf/sbbl

1621 scf/sbbl

2.509

2.607

Influence of field GOR values on the accuracy of the PVT data

Therefore every action should be taken to ensure that the gas and liquid flowmeters are properly calibrated, that they function properly and that all the necessary information is recorded. Omissions or erroneously recorded data may render a series of samples useless. Every sample should be accompanied with data sheets filled with all the information required to evaluate a posteriori its quality and as well as the sampling conditions. When the oil rates are reported at tank conditions, attention should be paid in the PVT laboratory to measure accurately the separator liquid’s shrinkage factor by flashing a part of the sample at the tank conditions reported at the time of sampling. Example: An oil with a high hydrogen sulphide content is produced through the primary separator that operates at 250 psia and 120OF. The oil flowrates are measured at the tank. Simulated runs for this used two scenarios for the prevailing tank temperature: 60OF and 100OF. The calculations showed that the separator liquid shrinkage factors would take values of 0.844 and 0.818 respectively that represents a difference of 3.1%. This difference will influence the separator gas to separator oil ratio that will be used for recombination. In the laboratory the field reported gas flowrates should be corrected using laboratory measured compressibility factors and specific gravities. It is also strongly recommended to measure in the lab the Z-factor of the separator gases particularly when permanent gases are present because the deviations between the actual values and the computed ones can be significant.

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Example: For an oil with a high permanent gas content (H2S, N2 & CO2) the Z-factor of the separator gas phase was predicted, using correlations to be 0.892 at 485 psia & 150 F. When the Z-factor measurement was performed in the Lab it gave a value of 0.85. I.e. a deviation of the order of 5% which directly affects the accuracy of the reported gas flowrates If there is chemical injection of glycol, methanol or wax inhibitors upstream of the separator, the injection should be stopped and sufficient time allowed for the chemicals to be purged from the separator. If it is not practical to operate without chemical injection, then the chemical used and injection rate must be recorded and a sample sent to the PVT laboratory with the samples.

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Sampling the Separator Gas Phase Three methods are available for sampling the gas stream. 1. by filling an evacuated sample cylinder 2. by filling a container after purging it with the separator gas to be sampled 3. by displacing the liquid from a brine-filled container The evacuation method is the recommended method for the gas sampling and all other methods would normally only be used as a last resort.

Vacuum gauge

Sampling bottle

Vacuum pump

Power cord

Gas Sampling Vacuum Method (Bottle Preparation)

The first method requires a vacuum system to be available at the wellsite with a suitable vacuum gauge to determine if the vessel is evacuated to the required level. The connecting line between the separator and the sample container should be purged with separator gas. The gas is then left to flow into the vessel for short period until the separator pressure is obtained.

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From separator

Pressure gauge

P 3

4

5

2 1

Sampling bottle

6

Gas Sampling Vacuum Method

The second method consists of filling the container with the separator gas by opening the top valve and purging it by throttling with the bottom valve. The container should be kept warm during the purge to avoid any condensation of the gas in the vessel in or otherwise the sample will not be representative. The sample is collected after several cylinder volumes of gas have been purged through the system. The third method requires that the sample cylinder is filled with brine and its top valve is subsequently opened to the separator gas outlet while the bottom valve is opened to withdraw the liquid. When all the liquid is displaced, the valves are closed and the container is ready for shipment. This method is not recommended due to the solubility in the brine of inorganic gases (e.g.CO2, H2S) as well as, to a lesser extent, of the light hydrocarbons present in the sample. The minimum number of separator gas samples in 20-litre bottles depends on the GOR and separator pressure but the general rule is as follows: o If the GOR < 1500 scf/bbl, then 2 bottles are required. o If 1500 < GOR < 3000 scf/bbl , then 3 bottles are required. o

If the GOR > 3000 scf/bbl, then 4 bottles are required.

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Example: As an indication of the volume of surface gas required for recombination, it is quoted that in order to produce in the laboratory cell 500 cm3 of a lean gas condensate at its dew point pressure (e.g. 5000 psia), roughly 20 litres of gas taken from a separator operating at 100 psia and 100OF are necessary. Corrosive gases such as H2S or CO2 can react chemically with the steel containers particularly if water is also present and due to this fact it is recommended that the gas stream is carefully dried before it enters the container. API RP 44 lists recommended specifications for gas-dehydration tubes. In addition, gases like the hydrogen sulphide are readily adsorbed by the surface active points of the walls of the sampling chamber whereas nitrogen diffuses through the metal lattice. Measurement of the gas composition, when these gases are present, should be performed at the wellsite immediately after sampling. This minimises their loss in the fluid’s composition that can otherwise render an“sour” sample “sweet” after transportation and storage A way to tackle this problem is to fill the chamber with the gas to be sampled and allow some time for the walls to become saturated with the adsorbed gases before it is evacuated and filled again with the sample. In this case considerably smaller losses can be expected. Alternatively a non-reactive sample cylinder coated in the same material as the NRS can be used. Sampling the Separator Liquid Phase In recent years there has been a QHSE initiative to eliminate the field the use of mercury for separator liquid sampling bottles. Sample cylinders, such as the CSB, with an internal piston and mixing device are in most common use today. Separator liquid is purged through a line between the bottom of the separator oil sight gas and the top of the CSB. The sampling is then performed by displacing the piston with separator liquid at a constant separator pressure. To avoid flashing the sampled oil, the bottom valve of the bottle should be opened slowly or preferably, a back pressure regulator can guarantee that the pressure in the chamber does not fall below the sampling pressure. If flashing does take place in the bottle, the sample will still be valid as long as the fluid remained monophasic while passing through the cylinder’s top valve.

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Separator oil sight glass Black valve

2

Vacuum pump

5

3

4

1

OIL 730cc oil bottle

70cc of gas 660cc of oil

Pressure gauge Hydraulic pump

P

7 8 Blue valve

9 6

Graduated flask

730cc of hydraulic oil

Separator Oil Sampling

Evidently, all connections used to conduct fluid from the separator to the sample container must be carefully purged with separator oil to avoid contamination of the sample with air. Before shipment, a gas cushion should be created for safety reasons as it was explained earlier for bottom hole samples. When the liquid yield at the surface is very small (e.g. lean gas condensate reservoirs) the liquid phase is not produced continuously and sometimes is withdrawn from the separator only after the test. Two risks are associated with this practice: 1. The collected gas was generated from the equilibrium that was prevailing at

the time of sampling whereas the oil sample exhibits an “average” oil phase composition over the long flow period. Even if an average GOR is used for recombination, the recombined fluid might not be truly representative of the original mixture. 2. The long oil retention time in the vessel might have cause compositional

variations of the hydrocarbon constituents due to gravity segregation. The oil sample that will fill the bottle after the test in this case would not be representative.

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If the separator oil sample contains quantities of water either in free form or in the form of emulsions, the aqueous phase has to be separated and removed from the hydrocarbons in the PVT lab before recombination is attempted. Possible Problems Encountered during Surface Sampling Inadequate Phase Split in the Separator Oil and gas well test separators are horizontal cylindrical vessels equipped with two separation sections. The inlet or primary separation section is located in the gas filled portion of the vessel and is designed to dissipate the momentum of the incoming flow stream so that the liquid continuous phase may fall free from the gas phase and enter the lower liquid collection section. In the secondary separation section, which consists of the bulk of the gas filled space, the remaining droplets are removed by the mist extractor. The effluent gas from a properly sized separator should contain normally no more than 0.1 gal of liquid/MMscf14. In addition, due to the inadequacy in separation, liquid entrainment can be provoked at high gas velocities by: o momentum transfer from the gas to the stationary liquid phase and to the associated pressure variations on the gas/liquid interface (waving) o creation of gas-liquid emulsions (foaming) The separator pressure can be adjusted to minimise any liquid carryover at the gas outlet. The chart below helps to determine this pressure according to the theoretical gas capacity of horizontal separators.

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Theoretical Gas Capacity of Horizontal Separators Example: Shell length : 10 ft Internal diameter : 39.6 in. Liquid depth : -6 in. Separator pressure : 800 psi

2000 1800 1600 1400

200 150

From chart ( 1 , 2 , 3 ) Theoretical gas capacity = 40 MMcf/D

-12

1200 1100 1000 900 800

100 90 80 70 60

-8 -4 0 -10

Pressure (psig)

Gas capacity (MMcf/D)

A

700

3

50

600

40

500

+4

400

30

+8

-8

2

300 20

-5

15

-4 -2

+12 Liquid depth (in.) Origin: center line

0

+8

+10

Gas specific gravity = 0.7 Oil specific gravity at 60oF = 0.85 Separator temperature = 80oF Shell length = 10 ft (For other lengths, multiply readings by shell length factor) No foaming and nonheading flow.

Internal diameter (in.) 40

5

Chart based on

1

30

50

60

150

10 9 8 7 6

+2 +4 +6

200

4 3

2

Theoretical shell length factor: 7.5 ft : 0.85 10 ft : 1 12.5 ft : 1.13 15 ft : 1.25

A

17.5 20 22.5 25

ft : 1.37 ft : 1.47 ft : 1.57 ft : 1.67

L 10

0.56

100 90 80 70 60 50 40 30 20

Theoretical Gas Capacity of Horizontal Separators

When standard test separators installed on high deliverability wells fail to achieve adequate separation between the two hydrocarbon phases and/or avoid liquid reentrainment, a misty flow regime instead of a single phase one reigns in the separator’s gas outlet. This is known as "liquid carry over" and the reported gas flow rates can be off because current gas meters malfunction when the liquid content exceeds a certain limit. Inevitably, the liquid flow rates measured at the same time on the other flow line will be wrong as well. Similar type of problems due to inefficient separation in the primary surface trap at the prevailing conditions can be encountered in the separator oil flow line. When testing reservoir fluids of low oil yield and the retention time of the liquid phase in the vessel is short enough to bring the gas-liquid interface close to the separator oil outlet, gas bubbles can be carried into the liquid flow line. This is known as "gas carry under" and in addition to altering the composition of the equilibrium oil phase it could also influence the quality of the meter readings.

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This failure of the primary separator to perform its function of adequately splitting the equilibrium phases has the two serious consequences for sampling: o the reported surface gas and oil flow rates are measured inaccurately o the quality of the recovered surface samples becomes questionable Inaccurate flow rates and/or the use of separator phases not in thermodynamic equilibrium leads to recombined samples which not representative of the original reservoir fluid. Non Equilibrium Phases produced in the Primary Separator It is often assumed that as soon as the well effluent enters the three phase separator its thermodynamic equilibrium adjusts instantly to the prevailing pressure and temperature conditions. This assumes that the mass transfer of the components between the two phases is completed right away and the required residence time allows for the segregation of the phases (gas from oil and oil from water). It should be considered, however, that the effluent in the upper parts of the production tubing flows in the diphasic regime and is subjected to a form of differential vaporisation process at varying temperature conditions. Despite the turbulence that is created, the flow pattern irregularities due to slug flow, that prevails in 80-90% of the cases, may not help to bring the effluent to thermodynamic equilibrium at the inlet of the separator. The mass transfer between the phases through which thermodynamic equilibrium is established, takes place through the interfaces. The largest possible contact area between the phases is required in order to accelerate the process. Once the phases are predominantly segregated after entering the vessel, in some cases, full equilibrium may never be attained. Although research has to be conducted to investigate the influence of time in establishing thermodynamic equilibrium, laboratory tests can be used to verify whether the recovered samples are or are not equilibrium phases at the field reported conditions15,9. Surface samples obtained from a separator, which operates at non-thermodynamic equilibrium conditions, can still be used for PVT analysis if they have been recovered simultaneously and a GOR value is available at the time of sampling.

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Quality Control of the Separator Gas and Liquid Streams The inefficiency of separation, as previously described, has led some operators to require onsite checks for controlling the quality of the separator output. Since carryover in the gas stream appears to be the major source of concern particularly for lean gas condensate reservoirs, techniques have been developed which aim to: o identify the problem whenever it exists and regulate, if possible, the separation conditions o attempt correcting the gas flow rate measured by the orifice meter o retrieve a representative sample from the diphasic mist flow of the separator gas line

The liquid carryover sampling technique is known in the field as “Isokinetic Sampling”16, although the term strictly means the withdrawal of fluid through a probe at the same vectorial velocity as the non disturbed stream upstream of the probe. There are various systems in use one of which is the Isokinetic Gas Sampling System (IGSS). The IGSS was developed after a theoretical review of existing isokinetic sampling systems followed by “proof of concept” flow loop experiments using a water mist in air at Schlumberger’s Clamart product centre. The flow loop tests established an experimental maximum absolute error in carryover concentration of +/- 1.5*10-5 l/hr and clearly demonstrated the importance of establishing a true isokinetic condition at the tip of the sampling probe in order to representatively sample the mist flow. The chart below compares the known level of carryover in the loop with the measured carryover by sampling at isokinetic and non-isokinetic conditions.

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M ea sured ca rry -over/ M ea sured ca rry-over by Isok inetic sa m pling

Sensitivity of Ca rry-O ver M ea surem ent to Sa mpling flow Ra te 1 .4 Q tota l= 2 0 0 sm 3/ hr

1 .2

3

Q tota l=4 0 0 sm / hr

1 0 .8 0 .6 0 .4 0 .2 0 0

0 .5

1

1 .5

2

2 .5

Sa m pling flow ra te/ Isok inetic sa mpling flow ra te

The IGSS design is, in effect, a miniature second stage separation process with features as follows:

o Sampling probe position at exit of gas outlet line to ensure there are no errors due to liquid carry-over deposition on the inner walls of the 6" gas line or additional liquid as a result of gas condensation in the 6" gas line. o True isokinetic flow conditions are established with a flow controller that matches the separator gas line velocity. o Real time measurement of liquid carryover allows the calculation of the corrected separator GOR for the duration of the stabilised flow through the well test separator. o The separation process provides a dry gas sample free of liquid carry-over and a liquid carry-over sample for the subsequent PVT recombination study. Please refer to attached flow schematic of the IGSS.

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Isokinetic Gas Sampling System IGSS

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Wellhead Split-Phase Sampling Shell International, through it’s Thornton Research Laboratory, developed a special sampling technique known as “split-phase sampling” that has been utilised particularly for gas condensate wells. A high pressure manifold is located upstream of the choke manifold by which the reservoir effluent is continuously withdrawn from the main flow line. The manifold includes a mixing block to homogenise the flowstream which is isokinetically sampled into a mini two-stage separation process with temperature control. This equipment, which acts as a laboratory type separator, continuously separates the two phases and the amount of liquid yield is directly measured offering an alternative route to the CGR. References 1.

L.E. Steele & G.E. Adams “A review of the Northern North Sea’s Beryl Field After Seven Years’ Production”, SPE 12960

2.

W.G. Riemens, A.M. Schulte, L.N.J de Jong “Birba Field PVT Variations Along the Hydrocarbon Column and confirmatory Field Tests”, JPT, January 1988, pp83-88

3.

Repeat Formation Tester, SMP-9070, October 1989, WTS Marketing Services

4.

P.J. Reignier and J.A. Joseph: “Management of a North Sea Reservoir Containing Near-Critical Fluids Using New Generation Sampling and Pressure Technology for Wireline Formation Testers”, SPE 25014, 1992

5.

A.R. Smits, D.V. Fincher, Katsuhiko Nishida, O.C. Mullins , R.J. Schroeder and Tsutomu Yamate: “In-situ Optical Fluid Analysis as an Aid to Wireline Formation Sampling”, SPE Formation Evaluation, June 1995, pp91-98

6.

M. B. Standing “ Volumetric and Phase Behavior of Oil Field Hydrocarbon Systems”, SPE of AIME, Dallas 1977

7.

Peresg, Alvaro M.M, Macias-Chapa, Luis, Serra, Kelsen,V. and Reynolds A.C:” Well-Conditioning Effects on Bubblepoint Pressure of Fluid Samples from Solution Gas Drive Reservoirs”, SPE 18530

8.

W.D. McCain Jr and R.A. Alexander: “Sampling Gas Condensate Wells”, SPE 19729, 1989

9.

API RP 44, First Edition January 1966

10.

J.W. Amyx, D.M. Bass and R.L. Whiting. “Petroleum Reservoir EngineeringPhysical Properties”, McGraw-Hill, New York, 1960

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11.

N.Varotsis and P. Guieze “On-site Reservoir Fluid Properties Evaluation”, JPT, August 1990, pp1046-1052

12.

L. P. Dake: “The practice of reservoir engineering”, Elsevier, 1994

13.

“Guidelines for Reservoir Fluid and Sampling”, Flopetrol

14.

M. L. Powers:”New Perspective on Oil and Gas Separator Performance”, SPE Production 7 Facilities, May 1993, pp77-83

15.

Hoffman, A.E, Crump, J.S and Hocott, C.R:”Equilibrium Constants for a GasCondensate System”

16.

W.D. Riley, R.P. Walters, S.D. Cramer, F.X. McCawley: ”Isokinetic Technique for Sampling Geothermal Fluids in Two-Phase Flow”, SPE 7885

17.

A. G. Collins: “Geochemistry of Oilfield Waters”, Elsevier, New York, 1975

18.

R.S. Metcalfe, J.L Vogel, R.W. Morris:”Compositional Gradients in the Anschutz Ranch East Field”, SPE Reservoir Engineering, August 1988, pp1025-1032

19.

F. O. Reudelhuber, Jr.:”Sampling Procedures for Reservoir Fluids”, SPE 816-G, December 1957

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RESERVOIR FLUID SAMPLING

Surface Sampling

Isokinetic Gas Sampling System (IGSS) IG Sampling Module

Sampling point

Isokinetic Sampling Probe

Separator

Separator 6” gas outlet line

Dry Gas Liquid Container

1440psi Test Separator Body

Control Valve

Flowmeter

Sampling Point

Liquid carry-over Sampling Point

SMART Data Acquisition System Stores liquid flowrate data

IG Sampling Controller Controls isokinetic flowrate Processes liquid flowrate data

? Oilphase, November 99

Reservoir Fluid Sampling & Analysis Course

Woodside Petroleum Ltd.

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