Spe 69427

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Copyright 2001, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the SPE Latin American and CaribbeanPetroleum Engineering Conference held in Buenos Aires, Argentina, 2528 March 2001.

This paper was selected for presentation by an SPE Program Committee following reviewof information contained in an abstract submitted by the author(s). Contents of the paper,as presented, have not been reviewed by the Society of Petroleum Engineers and aresubject to correction by the author(s). The material, as presented, does not necessarilyreflect any position of the Society of Petroleum Engineers, its officers, or members. Paperspresented at SPE meetings are subject to publication review by Editorial Committees of theSociety of Petroleum Engineers. Electronic reproduction, distribution, or storage of any partof this paper for commercial purposes without the written consent of the Society of

Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to anabstract of not more than 300 words; illustrations may not be copied. The abstract mustcontain conspicuous acknowledgment of where and by whom the paper was presented.Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractThe industry is focusing on cost reductions by saving on

expensive rig time and on reducing the impact on the

environment during well testing. Fluid samples for field

developments are more often taken solely by wireline

formation tester/samplers (WFT/S) and not necessarily

followed by flow to surface in a drill stem test. It has also

been more usual to drill exploration wells with oil based

mud in order to increase the drilling rate. These measuresreduce the likeliness for good quality fluid samples and

increase the uncertainty in field development projects

related to fluid data. A systematic approach to fluid

sampling is presented which discuss the different aspects

related the quality of fluid data obtained depending on the

sampling method, type of reservoir fluid system and

formation properties. Recommendations for these decision-

making processes are presented.

IntroductionManaging efficiently the production of natural gas and oil

requires accurate data on the characteristics of the reservoir

fluid and the phase and property change as the fluid movesfrom the reservoir through the transport and production

systems. The objective of reservoir fluid sampling is tocollect a sample that is representative of the reservoir fluid

at the depth and at the time of sampling and suitable for

laboratory studies of the physical and chemical properties

change during production. A non-representative sample will

not reflect the true properties of the reservoir fluid and may

result in costly errors in design and reservoir managementregardless of the accuracy in the laboratory data. One should

also keep in mind that the sample represent at the best only

the point in the reservoir where it was obtained and there is

no assurance that the sample is representative of the fluid

throughout the reservoir

PlanningA successful sampling program in a well requires g

planning. The right sampling equipment and techniq

have to be used. Also the timing is important. In m

situations the best conditions for taking a representa

sample of the reservoir fluid is during the exploration p

before the formation pressure has started to drop. S

specialised fluid studies may be identified later and

required samples taken successfully during the producphase. There will be differences in the challenge depen

on if the reservoir fluid is an oil, a near-critical fluid, a

condensate or a dry gas. The well will be logged prior to

reservoir fluid sampling is started. The logging will

information that is very useful in the planning of

sampling operation.

It has become more and more common in offshore w

to plan for most of the samples to be taken in open hole

wireline formation testers in order to save on expensive

time and to reduce the impact on the environment f

standard drill stem testing. The selected sampling inter

will be based on logs. Intervals with good permeability

good hole quality increase the chances for a succes

sampling run with a WFT. The height of the hydrocar

column may tell if a compositional change with depth

be important and if several intervals have to be samp

One should try to draw advantage of the bubble p

gradient (typically 0.2-0.4 bar/m) in a situation were

fluid is close to saturation. The pressure gradient in

hydrocarbon column together with the reservoir condit

will identify the type of reservoir fluid, Figure 1. The deof undersaturation may be evaluated from the use

correlations. Wire line fluid samples should and will in m

situations be taken as a part of the well logging operat

These samples will usually not be truly representative du

the difficulties with well conditioning and an effective c

up. There may also be effects on the reservoir fluid fromdecreased temperature in the vicinity of the well bore f

the mud circulation. A gas condensate can drop below

dew point and high molecular waxes/resins may dep

from an oil. WFT reservoir fluid samples may be

sufficient quality for many oil developments and have

potential of saving exploration cost by reducing the numof drill stem tests in a gas condensate reservoir. The qu

of the obtained sample should be assessed on site b

laboratory unit with the necessary equipment.

In any case the wire line fluid samples will be impor

to optimise the sampling program if the well would be

stem tested The logs and the WFT sample will mak

SPE 69427

A Systematic Approach to Sampling During Well TestingBjrn Dybdahl, Petrotech asa, and Hans Petter Hjermstad, Petrotech asa

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2 BJRN DYBDAHL, HANS PETTER HJERMSTAD SPE 6

or separator samples. It will further give information about

how easy the well can be conditioned prior to sampling. Inthe case of a gas-oil contact in the well the gas and oil

columns will be close to saturation and a representative fluid

sample impossible to obtain in situ. If the well is perforated

across the contact the separator phases may be recombined

in the laboratory to give representative samples of the fluids

on both sides of the contact1. Single phase sampling at thewell head may be feasible for a strongly undersaturated

reservoir fluid. If asphaltene deposition may be an issue in

an oil reservoir can be assessed from the saturation pressure

and the density of the reservoir fluid2. This will require

bottom hole samples with full pressure maintenance fromthe bottom of the hole to the sample reaches the laboratory.

If the nature of the reservoir fluid is a gas condensate the

leanness of the fluid and the expected production rate

determine if isokinetic split stream sampling at the well head

will be better method than the test separator for accurate

measurement of the sample recombination ratio 3,4,5. Theuse of partitioning tracers can also help to establish an

accurate gas-oil ratio (GOR) for surface samples 6,7. Thistechnique is very useful to provide samples and the

producing three-phase flow rates where the installation of a

large test separator unit is not attractive or feasible8. The

production rate during the highest flow rates of a gascondensate test may require additional equipment and

measurements in order to correct the measured condensate-

gas ratio for reduced separator efficiency 9,10,11.

In addition to samples for PVT studies more specialized

objectives for the samples may be given in the well

program. The sample volume required for some dynamic

experiments may exclude sampling by wire line fluid

samplers or bottom hole samples only. Larger volumes of

fluids will require flow to surface. Equally important maytrace elements in the reservoir fluid be and the detection

may require larger volume than bottom hole or wire line

samplers can give. Some elements may react or chemisorb

on the walls of the samplers and require inert linings.

Wireline formation samplingWireline formation testers (WFT) may give samples of good

quality with a sufficient sample volume for standard PVT

analyses of oils. They can be very cost effective. For gas-

condensates the volume may be too small for an extended

characterisation of the heavy ends. They can take samples

with very low and controlled draw downs. The closed in

sample can be pressurised to avoid phase separation

phenomena caused by the pressure and temperature

reduction when the sampler is lifted to surface. The main

problem with the WFT is limited possibilities to clean up the

formation from mud filtrate, especially if oil based mud

(OBM) has been used. The later generations of wire line

formation samplers have pump out capability and detectionsystems that can monitor the change in the mud filtrate

contamination of the sample12, 13,14. This has significantly

increased the quality of formation fluid samples taken in

open holes.

If the well has been drilled with oil based mud the

samples will be contaminated with the base oil filtrate. Thecontamination level will be determined by several factors

the formation before the sample is closed in and the

obtained by the probe against the formation are the mimportant. The contamination of OBM in the wireline f

sample can be reduced by pumping fluid from the forma

before the sample is closed in. The fluid is discarded into

well. There may be limitation to this due to safety asp

for high pressure gas wells since a small kick is produ

every time a volume of formation fluid is dumped. Theof an optical detector system that can tell the relative cha

in contamination level during the clean up is very usefu

This can be used to estimate the time needed to reac

reasonable clean oil sample and if this is feasible at all.

bubble point pressure of an oil will decrease with increacontamination and can be used for in-situ determinatio

the relative change in the contamination level du

pumping. There will be an exponential decay in

contamination level with pumped volume. Experience

shown that the OBM contamination in the sample

increase with the tightness of the formation, Figure 2. OBM contamination level will be higher at a given pum

volume from a low permeable formation than fromformation with better properties. It is not feasible to obta

clean sample from tight zones due to the large volumes

long pumping times needed. As a rule of thumb can be u

that a 100 times increase in pumped volume will be requin order to reduce the sample contamination level to

same level from a 10 mD zone compared to a 1000 mD.

sample will always have some degree of contaminat

There is no technique available to day to measure the c

up for a gas condensate system. The use of dual packer

combination with wireline formation testers can reduce

contamination from a tight formation. Larger volum

fluid can be produced for clean up and the formation se

clean up differently. The exponential reduction in Olevel in the produced fluid is replaced by a more plug-

flow behaviour giving a sharp transition between hi

contaminated and cleaner sample flow.

Oil systems are less effected by OBM contamina

than gas condensates and a higher contamination level

be excepted without dramatic changing the main f

properties. The bubble point pressure will decrease

increasing contamination and there will be effects on

formation volume factors, density and viscosity. The ef

on gas condensates depends on the relative difference in

molecular weight distribution of the C7+ fraction of

OBM and the pure condensate. If the OBM contamina

has higher carbon number components than present in

reservoir fluid the effect on the dewpoint pressure of

sample can be very significant even for a very sm

contamination. For these reasons it is not possible to gi

general contamination levet that can be accepted for a

condensate sample. A typical oil based mud will h

components in the carbon number range 9-25, withaverage molecular weight of C14. The effect on

dewpoint pressure for a North Sea gas condensate wil

small but the liquid drop out will be measured too h

Figure 3.

There are several techniques to determine

contamination level in the sample. This has to be meason a sample of the stabilised oil or condensate In

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SPE 69427 A SYSTEMATIC APPROACH TO SAMPLING DURING WELL TESTING

contamination level gives only an approximate value and

will be relative to the sample volume at reservoir condition.If the contamination level is known it is possible to correct

the composition of the contaminated sample based on the

assumption that the composition of the base oil does not

change during circulation.

At moderate contamination levels (>10 w-% in stabilised

liquid) it is possible to correct the PVT measurements madeon a contaminated sample with an Equation of State (EOS).

The technique is to calculated the effect of different amounts

with contamination and extrapolate back to the pure

reservoir fluid. The effect will not necessarily be linear. The

measured data on the contaminated sample is correctedrelative to the change from the extrapolation. Obviously,

any OBM contamination will increases the uncertainty in

the fluid property description and may be unacceptable for

some fluid systems. Water based mud systems are less likely

to effect the quality of the wireline hydrocarbon formation

sample.In order to reduce the contamination the sampled

interval in the well should be chosen from assessment of thepermeability and the quality of the hole. A hole with large

wash outs will not provide a good seal for the WFT. A

calliper log is useful. Also, intervals with large loss of

drilling fluids should be avoided as targets for the wirelineformation sample.

The use of water based mud will create a similar

contamination problem for formation water samples taken

by WFT. A tracer like sodium thiocyanate can be added to

the mud system and the composition of the pure formation

water calculated from a multi-ion analysis of the mud filtrate

and the contaminated sample.

The quality of the WFT sample should be assessed at

surface and a decision whether the objectives regardingsamples have been reached or if further sampling is needed

either by more WFT runs or by DST testing. If no

information is available from comparable wells the decision

has to be based on that the samples give consistent bubble

point pressures, a reservoir fluid density consistent with the

measured pressure gradient and an acceptable contamination

level in the case of OBM. Small laboratory packages

designed for offshore use are available. The saturation

pressure for a gas-condensate is more difficult to measure on

site and will not be readily available. For a gas-condensate

only the contamination level and the density may be used as

evaluation criterions at site. This evaluation may not be fully

conclusive regarding the quality of the samples. The

decision flow in WFT sampling and sample evaluation is

presented in Figure 4. If drill stem testing is decided the

information about the nature of the fluid, degree of

undersaturation and the gas-oil ratio will also be valuable for

planning of the test and the sampling operation.

Conditioning of well for DST samplingThe objective of clean up and conditioning a well prior

to sampling is to remove all fluids introduced into the well

and the near well bore region during the drilling process.

Further, the conditioning should remove any altered

reservoir fluid from the near well bore region. The clean upconsists of flowing the well to remove the drilling and

replace it by representative fluids from a more dis

portion of the reservoir. Conditioning the well besampling is important and is especially important when

reservoir fluid is close to saturation at the prevai

reservoir pressure. Shutting in the well to restore

pressure will not necessarily change the altered fluid bac

the original reservoir fluid. It is generally necessary to f

the well and displace the affected fluid. The initial flow also re-establish the reservoir temperature in the near

bore region.

During the clean up the well will be flowed at a low

or at several decreasing rates. The flow rate has to

sufficient to lift the drilling fluids to surface. For condensate the linear velocity of the flow should exceed

1.5 m/s at the well head15. The clean up process wil

monitored by measurement of the producing gas-oil r

the well head pressure and temperature and by chem

analysis of the produced fluid. The chemical analysis

tell when the drilling fluids and mud filtrate have bdisplaced and a stabilised GOR will in principle indicate

the unaltered reservoir fluid is produced. In ordercompare GORs from different flow periods the effec

changing separator conditions has to be compensated.

Gas condensates behave differently than reservoir

Experience has shown that a gas condensate closesaturation pressure can be produced representatively e

though the flowing bottom hole pressure is below the

point pressure, Table 1. This observation has b

established from analysis of a proprietary datab

(Petrotech) with 93 gas-condensate well tests and

individual flow rates, all with both test separator and

stream measurements at the well head. Within the accur

of the measurement it has not been possible to see an ef

on the producing gas-oil ratio or the properties of produced condensate. During a relatively short well test

drainage area will be small and the gas phase

condensate droplets will be produced with large li

velocities. The drop sizes will be very small with l

tendency to impact on the formation. This is believed t

the reason that gas condensates can be produced below

dewpoint pressure without loss of retrograde liquid. Th

true for relatively short well tests and from formations w

average to good properties. If the production is continue

a longer time period loss of retrograde liquid will take p

with the following increase in GOR.

Bottom hole samplingBottom hole samples seems attractive since they repre

the nearest approach to sample within the reservoir and

of solid depositions in the flow line can be avoided. T

may be taken on wire line or enclosed in a tubing conve

carrier. Tubing conveyed bottom hole samplers have

potential of saving rig time by eliminating the need fseparate sampling flow. Several sampling chambers wil

filled during a run. The start of the sampling can

triggered electrically, acoustically or mechanically ei

from the rig, by a timer or by a pre-designed logic built

the tool. The sampling principle relies on single p

hydrocarbon flow in the well and is primarily suitedundersaturated reservoir oils Single phase may not

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tight formations. The well has to be properly conditioned

and producing with a pressure above the saturation pressureof the fluid at the point where the sampler has been

positioned. Below the bubble point there is no guarantee that

oil and gas enter the sampler in the right proportions. The

position of the water-oil and oil-gas contacts in the well can

be obtained from the pressure gradients and the sampler

should be positioned between. The well should be closed inor produced at a low rate during the sampling and the

sample not taken before the altered reservoir fluid has been

completely displaced. If the well is flowing two phases

during the conditioning flow bottom hole sampling is not

recommended. Shutting in the well will not bring the gas orretrograde condensate back in single phase. The method is

not recommended for gas condensates. Bottom hole

sampling may work for rich gas condensates where the

liquid yield is sufficient to obtain a good characterisation of

the heavy ends of the composition.

Modern bottom hole samplers can control the samplingrate accurately and pressurise the sample before it is moved

to surface. They are especially suitable for oils whereasphaltenes may drop out during pressure reduction but also

give advantages in the transfer of gas condensates samples

since the sample can be maintained in single phase. The

decision flow for sampling of reservoir oil sampling ispresented in Figure 5 and for near critical fluids in Figure 6.

For oils close or at saturation it has been shown that

separator sampling is more likely to give representative

samples than the use of bottom hole techniques16.

The representativity of the sample will be evaluated

from the measured saturation pressure at reservoir

temperature. The saturation pressure has to be below the

reservoir pressure. Duplicate or triplicate samples should

always be taken in a sampling run. The samples should giveconsistent saturation pressures in order to be defined as a

good sample. The sample is suspicious when the measured

saturation pressure equals or is above the flowing pressure at

the sampling point. In the case of a sample for asphaltene

study the bubble point measurement can for obvious reasons

only be made on a small portion of the sample. The flash

GOR of the sample should also be consistent with the

measured separator GOR during the later DST flows. The

test separator GOR for the bottom hole sampling flow will

usually not be accurate enough due to the low flow rate.

Single phase well head samplingSamples may be obtained directly on the well head if it is

known that the flow is in single phase. The method works

for both oils and gas condensates. When the conditions well

head sampling is satisfied this can be the most reliable,

efficient and cost effective way to collect reservoir fluid

samples.

Normally the required single phase conditions will onlybe satisfied for the earlier and lower flow rates of a well test

when also the flowing temperature on the well head will be

low. Well head sampling may not be the best method for

some gas condensates with high wax formation temperatures

and for oils where asphaltene flocculation occur due to the

pressure reduction between the reservoir and the wellhead.Where these aspects are important bottom hole sampling

Surface sampling methodsSeparator sampling. Separator sampling consist of takisample of the equilibrium oil and gas from the test separ

while making accurate measurement of the separator oil

gas production rate which prevail at the time of sampl

The samples can be taken as soon as the well has b

conditioned and both phases should be sampled essent

at the same time. The sampling time should be longer the retention time of the oil or condensate phase in the

separator. The two samples will be recombined in the s

proportion as the measured gas and oil rates to giv

physical sample of the well stream. Therefore an accu

measured gas-oil ratio is of utmost importance. challenge with separator sampling is primarily to corre

measure the recombination ratio and not tak

representative samples. Large volume samples of each p

are easily obtained. This may be the only method to sam

a lean gascondensate in order to get sufficient condensat

make characterisation of the heavy end.It is recommended to base the sample recombina

ratio on an analysis of the gas-oil ratio for all flows andonly the short period when the samples were taken.

GOR measurements should be corrected to the s

reference conditions both within and between the flo

This analysis will identify if any two phase flow effectthe inflow to the well has effected the well str

composition and thereby the test separator gas-oil ratio.

flow periods with valid samples will be identified.

correction is easily made with an EOS. The relative effe

changing separator conditions can accurately described

this calculation. The derived GOR for the valid flows wi

corrected back to the actual pressure and temperature du

the sampling to give the recombination ratio for

identified sample set. This procedure quantifies uncertainty in the measured gas oil ratio, which also ca

translated into the uncertainty for each single componen

the recombined composition11. Sample sets should be ta

from more than one flow.

The liquid flow rate is measured by meter. The

mechanical meter factor will change with the produc

rate and a new meter calibration run should be perfor

for each flow. The rate dependence of the meter fa

should be established based on an analysis of all calibra

runs. About 35 m3/d will be the lower limit ( 2" F

meter). Below this value the uncertainty in the liquid

will be large and strongly influence the measured gas

ratio. Testing of lean gas condensates will often req

other means for measurement of the condensate produc

rate. Gauge tank measurement will not provide

necessary accuracy. The separation process will also

different from the flow through the meter giving diffe

shrinkage. In this case the best method will be the us

isokinetic split stream sampling at well head.All test separators will have an upper gas capacity li

At higher gas rates a fraction of the condensate inflow

be lost through the separator gas outlet. The entrained li

starts to be significant for the measured condensate-gas r

when the separator efficiency is reduced below 97 %.

separator efficiency is defined as the ratio between condensate collected in the separator and the

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standard test separator (42" x 10') this efficiency level is

passed at a gas production rate of about 10.000 m3/d11.This is the actual gas rate at the operating pressure and

temperature of the test separator. Demistors will have little

effect on this capacity limit. The entrainment is caused by

very small droplets and by secondary droplet generation in

the demistor due to flooding. It will not be practical to

increase the size of the test separator to completely preventliquid entrainment. Larger separators and cyclon separators

will give a higher capacity before the carry-over starts be

significant, but not sufficient to secure a correct condensate

rates without correcting for the liquid lost through the gas

outlet. Service companies claim too optimistic capacitylimits for their separators. It is obvious that a correct fluid

description will not be possible for higher gas rates without

an independent measurement of the entrainment rate.

The separator efficiency can be measured by an

isokinetic probe inserted in the separator gas outlet. The

conditions are very favourable for this measurement at theconditions with reduced separator efficiency through small

droplets, high velocity and large void. It is very likely thatthe method not will succeed in obtaining a representative

split stream sample at low flow rates. However, at low flow

rates the separator is close to 100 % efficient and the amount

of entrained liquid in the outlet gas insignificant. Themethod is self-regulating in the sense that the conditions that

are favourable for split stream sampling also are those that

reduce the separator performance. Several methods can be

used to determine the condensate content of the isokinetic

sample. The method must be able to distinguish between

condensate and water. Both will be present in the separator

gas outlet flow.

The separator gas rate is measured with an orifice. This

measurement will be influenced by entrained liquid and willresult in an over-reading of the gas rate when the

entrainment rate is high. It is the entrainment rate or the void

fraction that determine the error in the reading and not the

separator efficiency11. However, the measured efficiency

can be used to correct the gas rate from the orifice readings,

Figure 8. The decision flow for DST sampling of gas

condensates is presented in Figure 9.

Split stream sampling at wellheadsThis method is superior to the test separator when testing

lean gas condensates16, Figure 7. Low well head

temperatures can create reduce the representativety of

samples taken at the separator. Wax precipitation may affect

the samples and producing in the hydrate region will require

injection of inhibitors. A heater before the production choke

will not eliminate the need for hydrate inhibitors in deep

water wells. The problem is larger for gas condensates than

for oils due to the lower heat content of the flow and the

higher wax formation temperatures. If the use of hydrateinhibitors can not be avoided glycols should be chosen over

methanol due to the much lower solubility for hydrocarbons.

The method was originally developed as a one point

measurement of the condensate-gas ratio with the capability

of taking samples with accurate pressure and temperature

control3,4. A mixing manifold is used to break the annularflow and to distribute the liquid droplets homogeneously

been improved by using a traversing sampling probe tha

the droplet and velocity distribution. The traversing pshould be used for gas rates below 500.000 Sm3/

Condensate-gas ratio measurements by split str

sampling at the wellhead can with advantage also be u

where the test separator has the sufficient accuracy. It

provide an independent measurement of the produ

condensate-gas ratio and thereby a better base determination of the correct value for the reservoir fl

This sampling and measurement technique consist of sm

and easy installed units and can also be used instead of

test separator provided gas is present as the continu

phase at the well head.

ConclusionTo base PVT properties used for field developments

reservoir management solely on samples obtained by W

may be costly even though they may look attractive fro

cost perspective in the exploration phase. The use ofbased mud will always give contamination in the W

samples. They may provide adequate samples for oil some near critical systems from formations with g

permeability, but should not be used for gas condensate

the only source for fluid data. WFT samples will pro

very useful information for planning the sampling progduring the following drill stem test. Analytical capab

should exist on site to evaluate the quality of the sample

type of reservoir fluid.

Bottom hole sampling is the preferred sampling me

for undersaturated oils, near critical fluids and rich

condensates. The capability of maintaining the sample a

bottom hole pressure may prevent precipitation

eliminate errors in the sample transfer.

Representative samples of gas condensates and saturreservoir fluids are most likely obtained from the

separator. At flow rates above 10.000 m3/d at separ

conditions the liquid entrainment in the separator gas sh

be measured in order to correct for carry over. In the cas

reduced separator performance the measured gas rate sho

be corrected for the over-reading due to the entrainm

Condensate flow rates below 35 m3/d has to be measu

with an alternative method to the Floco-meter.

Isokinetic split stream sampling at the well h

provides an attractive alternative to the test separ

sampling. It should be the preferred method for lean syst

producing with high gas rates.

References

1. Fevang, O; Whitson, C.H; Accurate Insitu Composistion

Petroleum Reservoirs, SPE 28829 (1994)

2. de Boer, R.B; Leerlooyer, K; Eigner, M; van Bergen, A.

Screening of Crude Oils for Asphaltene Precipit

SPE 24193 (1992)

3. Dixon, A.G; Erbell, H.K; Hydrocarbon Fluid Evaluation

Hydrocarbon Components, Gas Quality, Elsevier Sci

Publishers, 579-588 (1986)

4 Nautilus Ventures B V ; Thornton Minilab and Well H

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5. Witt, C.J; Crombie, A; Vaziri, S; A Comparison of Wireline

and Drillstem Test Fluid Samples from a Deepwater Gas-

Condensate Exploration Well, SPE 56714 (1999)

6. Nederveen, N; Washington, G.V; Bastra, F.H ; Wet Gas Flow

Measurement, SPE 19077 (1989)

7. Petrotech A/S; Use of Sampling Apparatus for a Calibration

Electronic Massflow Meters in Pipeline US Patent P 6186

5894080

8. Konopczynski, M.R; de Leeuw, H; Large-Scale Application

of Wet-Gas Metering at the Oman Upstream LNG Project

SPE 63119 (2000)

9. Petrotech A/S;Method and Apparatus for Isokinetic Fluid

Sampling UK Patent P 5855 2299167

10. Petrotech A/S;A Device for Positioning of a Trottle/Mixing

Body UK Patent P 5952 2301297

11. Hjermstad, H.P; The Significance of the Test Separator

Efficiency in Testing of Volatile Oil and Gas/CondensateWells, Lerkendal Petroleum Engineering workshop,

Trondheim Feb. 5-6, 1992

12. Michaels, J; Moody, J; Shwe, T; Wireline Fluid Samplin

30610 (1995)

13. Smits, A.R; Fincher, D.V.; Nishida, Katsuhiko; Mu

O.C.; Schroeder,R.J.; Yamate, Tsutomu; In-Situ Optical F

Analysis as an Aid to Wireline Formation Sampling,

26496 (1995)

14. van Dusen, A; Williams, S; Fadnes, F.H; Irvine-Fortescu

Determination of Hydrocarbon Properties by Optical Ana

during Wireline Fluid Sampling, SPE 63252 (2000)

15. Turner, R.G; Hubbard, M.G; Dukler, A.E; Analysis

Prediction of Minimum Flow Rates for the Contin

Removal of Liquids from Gas Wells, J. Pet. Tech. T

AIME, 246 (1969)

16. Towler, B.F; Reservoir Engineering Aspects of Bottom

Sampling of Saturated Oils for PVT analysis, SPE 1

(1989)

17. Brummens, H.Field Experience with Gas Condensate

Testing without a Test Separator SPE One-day semBergen March 23, 1999

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Figures & Tables

Figure 1. Fluid type identification from the density at reservoir conditions

Figure 2. OBM contamination in WFT samples versus log permeability(CGR = 100 85 Sm3/Sm3, Pumped volume =10 liter)

200 400 600 800

0.35

0.40

0.45

0.50

0.55

Oil

Gas Condensate

Pressure (bar)

Reservoirfluiddensity(g

/cc)

0

10

20

30

40

50

60

70

80

90

100

10 100 1000

Permeability (mD)

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Figure 3. Calculated effect of OBM contamination on the liquid drop out during CVD on a North Sea Gas Condensate

(the contamination is given relative to reservoir fluid sample)

0

5

10

15

20

25

30

0 50 100 150 200 250 300 350 400

Pressure (bar)

4 mole-% OBM

2 mole % OBM

0 mole % OBM

CVD

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Figure 4. Decision flow diagram of planning, sampling and evaluation of reservoir fluid samples from wireline formation teste

Logging

S a m p lin g b y W ir e L in e F o r m a t io n T e s t e rs (W F T )

Pressure,

Temperature

Pressure

Gr adient

Porosity,

Hole Quality

W F T

Plan

Mud

WBM, OBM

Decision S ampleOK

Fluid T ype,

Saturation Pres.

New Sample

DST Sampling

Sampling

Q C

GOR, D ensity, OBM, P sa t

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Table 1. CGR versus flowing bottom hole pressure for a gas condensate (Pi = 358 bar, Psat = 247 bar based on the average CG

Flow Pressure CGR St. Dev.

period bottom hole 20 bar, 25 C CGR

bar m3/KSm3 %

Sampling 150.7 28.4 5.3

Max 115.7 28.8 6.7

MF 1 195.4 29.3 10.8

MF 2 158.3 31.1 7.8

Figure 5. Decision flow diagram for DST sampling of a reservoir oil (Psat= saturation pressure,

Pbh=flowing bottom hole pressure, Pwh=flowing well head pressure, Pi=Reservoir pressure)

W F T

D ST Sa mpling - O il

Nature of

Reservoir

Fluid

P sa t

Method

O il

Bottom HoleSample W ell HeadSample SeparatorSample

P sa t < P bh P sa t ~ P i

P sa t< P w h

Gascond.

Near crit. fluid

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Figure 6. Decision flow diagram for DST sampling of a critical fluid (Psat= saturation pressure,

Pbh=flowing bottom hole pressure, Pwh=flowing well head pressure, Pi=Reservoir pressure)

W FT

D ST Sa mpling - N ear C riti ca l F lu id

Nature of

Reservoir

Fluid

P sa t

M e t h o d

Bottom Hole

Sample

W ell Head

Sample

P sa t < P b h P sa t ~ P i

P sa t< P w h

Gascond.

Near Crit. Fluid

Separator

Sample

O il

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Figure 7. Comparison between isokinetic split stream GOR measurements (Multisplit) and the value

obtained from the test separator (31 individual flows, Test separator GOR +- 13.5 % Multisplit GOR +- 5.5 %)

Figure 8. Gas rate correction factor due to condensate entrainment as a function of separator

efficiency and CGR in separator outlet gas

0 500 1000 1500 2000

Thousands

Gas Rate (Sm3/d)

-30

-20

-10

0

10

20

30

Errorinmeasure

dGOR(%)

Test Sep.

MultiSplit

70 80 90 100

0.75

0.80

0.85

0.90

0.95

1.00

1.25 m3/KSm3

1.00 m3/KSm3

0.50 m3/KSm3

0.25 m3/KSm3

Separator Efficiency (%)

GasRateCorrection-factor

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Figure 9. Decision flow diagram for DST sampling of a gas condensate

Natur of

reservoir

fluid

Q o

S m 3/d

Q g

m 3/d @

P s, T s

Test Separator

Isokinetic

measurement

sep. efficiency

>10000 35

Split s tream

at w ell head

< 351

Gas Condensate

Crit.Fluid

O il

D S T S a m p l in g - G a s C o n d e ns a t e

W F T

1) 2 " Floc o m eter2) Sandard test s eparator 42" x 10' (1440 psi)

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