CFA Composition Fluid Analyzer

Applications■ Assurance of gas sampling

above the dewpoint

■ Downhole measurement offluid compositional gradient

■ Downhole determination of gas/oil ratio (GOR) or condensate/gas ratio (CGR)

■ Economic valuation of layeredgas reservoirs without takingsamples

■ Scanning fluid compositionby depth

■ Monitoring changes in fluidcomposition due to injectionor production

■ Downhole determination of reservoir architecture,including layer connectivity

Benefits■ Representative samples

(single-phase, acceptablelevel of contamination)

■ Minimal time required forsample acquisition

■ Early determination of GORor CGR for reservoir valuation

■ Determination of fluid compositional gradient forreservoir modeling

■ Early determination of layerconnectivity for completiondecisions

Features■ Quantitative weight-percent

measurements of hydrocarbon,water(H2O), and carbon dioxide (CO2)

■ Real-time contaminationmonitoring for sampling in wells drilled with oil-basemud and deciding when to sample

■ Measurement of fluorescenceemission

■ Measurement of light absorption at selected wavelengths

■ Efficient integration with all other MDT* ModularFormation Dynamics Testermodules

Expanded technology for gas sampling and analysisDownhole fluid analysis by the CFA*Composition Fluid Analyzer module ofthe MDT Modular Formation DynamicsTester ensures recovered samples are rep-resentative—one of the reasons the MDTtool is the industry standard for acquir-ing reservoir fluid samples on wireline.

The CFA analyzer builds onSchlumberger’s proven downhole oilanalysis experience to advance the tech-nologies of gas sampling and analysis.

As a single-phase reservoir gas flowsthrough it, the CFA analyzer uses a near-infrared optical absorption spectrome-ter for real-time determination of theconcentration of

■ methane (C1)

■ ethane-propane-butane-pentane(C2–C5)

■ heavier hydrocarbon molecules (C6+)

■ H2O

■ CO2.

From this composition information,the condensate yield, or CGR (theinverse of GOR), is obtained.

The CFA module also measures fluorescence emission to identify fluidtype and to ensure that samples areacquired above the dewpoint for a gas condensate.

The importance of accurate fluid sampling and analysis Accurate determination of in situ sampleproperties is essential, not only to char-acterize and produce a reservoir, butalso to design well completions, subseatiebacks, and topside facilities. Reservoirfluids composition, phase behavior, andflow assurance (solids deposition) areroutinely measured by a pressure-volume-temperature (PVT) laboratory such asOilphase-DBR, the world’s leading pro-vider of PVT laboratory services.

Fluorescence detector

Spectrometer (gas analyzer)

RF CH 470 nmFL CH#1 >550 nmFL CH#2 >680 nmLight source 470 nm

Lamp

Sample flow

Near-infrared optical absorption spectrometryand fluorescence emission measurements areused to determine gas-fraction concentrationsand to identify fluid types, respectively, as fluidsflow through the CFA module.

Optical density(path length = 2 mm)

2.0

1.5

1.0

0.5

0.0

Wavelength (nm)

1,600 1,700 1,800 1,900 2,000 2,100

(Normalized) C1 C2–C5 C6+ CO2

Shown here are optical absorption spectra for C1, C2–C5, C6+, and CO2 compounds. The absorption spectrumfor H2O is not shown. An optical density of 0 means no light is absorbed as it is transmitted through the fluid;a density of 1 means 0.1 of the light is transmitted; and a density of 2 means 0.01 of the light is transmitted.

Downhole reservoir fluid analysisprovides assurance that captured sam-ples are representative. Since the CFAmodule identifies fluid properties inreal time as it passes through a zone of interest, sampling operations can be modified according to the nature of the fluids being sampled.

Reservoir fluids can be in gas or liquidphase. Hydrocarbon gases can be dry,wet, or condensate (alternatively catego-rized as dry, lean, or rich). Dry gas willnot precipitate liquid during samplingdownhole nor at surface separator con-ditions. Wet gas cannot precipitate liq-uid during downhole sampling, but itwill precipitate small amounts at sur-face temperature and pressure. Gas con-densate will precipitate a liquid phasedownhole if the flowing pressure goesbelow its dewpoint.

Fluid composition answers from optical absorption spectrometry data The CFA module contains an opticalabsorption spectrometer that uses visi-ble and near-infrared light to quantify afluid’s composition as it flows throughthe tool. The spectrum of light is trans-mitted through the fluid to an array ofdetectors tuned to selected wavelengths.The amount of light absorbed by thefluid depends on its composition. Themeasured absorption spectrum is rep-resented as a linear combination of theunique absorption spectra for C1, C2–C5,C6+, CO2, and H2O, allowing determi-nation of the weight percent of eachmolecular group.

The CFA module measures the compositions of single-phase fluids. Ingas reservoirs, oil vaporized in the gas

will precipitate as liquid condensate atsurface temperature and pressure con-ditions. The CFA measures the compo-sition of the condensate while it is stillin the gas phase. This vaporized com-position is the C6+ fraction. From theratio of the C6+ fraction to the C1–C5fraction, the CGR is determined. CGRindicates the condensate yield, or thebarrels of liquid that will condense from1 million scf of gas at standard tempera-ture and pressure conditions.

Fluid identification from fluorescence emission dataThe CFA module measures fluorescenceemission using a narrow-spectrum lightsource, a blue-light-emitting diode. Thelight is absorbed by the fluid in contactwith the window on the flowline of thetool and is then reemitted as a widespectrum of longer wavelengths.

The fluorescence emission spectrumvaries with the amount of condensatevaporized in the gas; the spectrum isreduced whenever the pressure of acondensate falls below its dewpoint.Therefore, the spectrum can be moni-tored to ensure the reservoir fluid issampled above its dewpoint.

Information to optimize productionThe CFA instrument can provide pro-duction-optimizing information not pre-viously available in real time on wireline.This includes fluid scanning for a com-positional gradient in a thick reservoir,identification of layers with differentfluids, downhole evaluation of CO2level, downhole determination of dew-point, secondary recovery monitoring,and oil-base mud sampling.

Monitoring the fluorescence emission spectrum can help ensure that reservoir fluid is sampled aboveits dewpoint.

Fluid scanning for a compositional gradient in a thick reservoirFluid scanning refers to the evaluationof reservoir fluids at a large number ofdepths using the combination of down-hole analysis and a short pumpout periodavailable with the MDT sampling string.No fluid sampling is required. In a thickgas reservoir, CFA scanning can be usedto measure the compositional gradientof the reservoir fluid.

Identification of layers with different fluidsEven using logs and seismic data, it canbe difficult to determine which layersare connected in layered gas reservoirs.Gas composition is the same through-out connected layers; so is gas pressure.But gas compositions or gas pressurescan also be the same in layers that arenot connected.

An accurate determination of con-nectivity is fundamentally important.The commingling of gases of differentcomposition can be very undesirable—particularly if some gases have unac-ceptably high percentages of CO2.

Gas samples can be acquired andanalyzed at the surface in a relativelybrief time frame if there are not manylayers; but what if a multilayered wellneeds to be cased and perforated in amatter of days? Using the CFA tool tomeasure gas composition is a fast andaccurate solution.

100

80

60

40

20

0C1 y = x

Tool estimation

(wt %)

True mass fraction (wt %)

0 20 40 60 80 100

100

80

60

40

20

0C2–C5y = x

True mass fraction (wt %)

0 20 40 60 80 100

100

80

60

40

20

0C6+y = x

True mass fraction (wt %)

0 20 40 60 80 100

100

80

60

40

20

0CO2y = x

True mass fraction (wt %)

0 20 40 60 80 100

Laboratory evaluation and calibration of the CFA module was conducted in the Oilphase-DBR PVT laboratory in Houston. A range of hydrocarbon systems wasevaluated at high pressures and temperatures to ensure fluids were single phase. The composition determined optically (tool estimation on the Y-axis) agreed withthe composition measured by gas chromatography (true mass fraction on the X-axis).

Depth(m)

X,X60

X,X80

X,X00

X,X20377 378 379 380 381

Pressure (bar)

Pressure Gradients CFA Composition (wt%)

C1 C2–C5 C6+

GOR (scf/bbl)

7,900

2,500

2,000

1,800

1,500

0.599 g/cm3

0.374 g/cm3

0.982 g/cm3

The change in fluid composition with depth in a thick sand reservoir yields information that is difficult to obtain with any other technique. Combined with fluid density data from the pressure gradient survey, it gives an improved evaluation of the fluids in place.

C1

C2–C5

C6+

200150100500

250200150100500

Station depth (X ft)

Station depth (X + 17 ft)

Time (sec)

Time (sec)

The dramatic difference in gas composition measured with the CFA instrument in two layers 17 ft apartconfirmed the layers are not connected.

Downhole evaluation of CO2 levelOccasionally a gas is identified on logs as a hydrocarbon, but it is laterfound to be primarily CO2. High con-centrations of CO2 can reduce a reser-voir fluid’s value and even render its production uneconomical. Andbecause CO2 cannot be released to the atmosphere, its disposal is anexpensive issue.

The CFA module’s ability to meas-ure CO2 concentration can prevent its being misinterpreted from log data as a hydrocarbon.

Downhole determination of dewpointGas samples must be captured abovetheir dewpoint for meaningful reservoirfluid analysis. Sampling and acquisitionwith the CFA module can assure thatthey are.

Secondary recovery monitoringThe CFA module can be used to moni-tor gas-injection patterns in secondaryrecovery development projects. In agas-injected field in the Middle East,the operator had trouble modeling andmonitoring injection in the layers beingproduced. The CFA module was run totrack injection in real time.

The CFA module identified and quantified gas injection in the reser-voir’s different layers, allowing the

operator to update the reservoir modeland modify the injection pattern toimprove field recovery.

Pumping Stopped 3510.0 C

1377 1386 1395 1404 1413 1422 1431 1440 1449 1458 1467

CFA Apparent Hydrocarbon Density

(AHYD_CGA)

CFA Methane Partial Density (METH_CFA)

CFA C6+ PartialDensity (HEX_CFA)

CFA CO2 PartialDensity (CO2_CFA)

0 (G/C3) 0.5

0 (G/C3) 0.5

0 (G/C3) 0.5

0 (G/C3) 0.5

0 (G/C3) 0.5

CFA CGR(CGAR_CFA)

0 (UBCF) 200

CFA C2–C5 Partial Density

(ETH_CFA)CFA GOR

(GOR_CFA)

0 (F3/B) 25,000

ElapsedTime(S)

Methane

C2 C5

C6+

CO2

Water > 80%

Water Volume Fraction

CO2OFF

Highly Scattering Fluid

CFA Optical Density Channel 1(FAOD1_CFA)

0 1

CFA Fluorescence Channel 0 (FLD0_CFA)

0 (V) 1

CFA Fluorescence Ratio (FLRA_CFA)

0 1

Time Mark Every 60 s

H

M

L

PIP SUMMARY

Seal MRMS_2, bottle 3

The CFA instrument measured a significant fraction of CO2 in this reservoir fluid.

Time

Pressure

Dewpoint

Absorption spectrometer

Flourescence signal

Above Pd Below Pd

Optical scattering due to formation of mist prior to condensation

Flourescence transientfollowed by reduction

With the CFA module, fluid properties data are available before sampling so gas samples can be captured above their dewpoints.

Oil-base mud samplingIn some oil reservoirs there is little dif-ference between mud-filtrate and reser-voir-fluid colorations measured by theabsorption spectrometer. In this com-mon situation, simply monitoring thecolor channels while sampling is notsufficient to determine the contamina-tion level.

While their colorations may be simi-lar, filtrate and lightly colored hydrocar-bons have different compositions. CFAreal-time composition analyses providea better understanding of the contamina-tion level of fluid flowing through theMDT tool and help determine when thebest samples can be collected.

In a Gulf of Mexico deepwater reser-voir, the color channels indicated littledifference between filtrate and hydro-carbon. By monitoring the compositionchannels, the operator understood thecleanup period and was able to collectpristine-quality samples in a manneroptimized to operations in this expen-sive environment.

C1 C6+C2–C5

0.2

0.1

0.0

1.00

0.75

0.50

0.050

0.025

0.000

C2–C5 (g/cm3)

C6+ (g/cm3)

C1 (g/cm3)

Time (min)

1 2 3 4 5 6 7

CFA composition channels clearly indicate a decrease in contamination over time.

C1 C2–C5 C6+

Depth A: No injected gas

Depth B: High concentration of injected gas

Depth C: Some injected gas

Depth D: Some injected gas

The CFA module was used to analyze fluid at four depths. The injected gas swept Depth B most efficientlyand Depths C and D to some degree, but no gas reached Depth A. This demonstrated that the layers at Depths A and B are not in communication.

About the MDT Modular Formation Dynamics TesterThe CFA analyzer is one of the mod-ules of the innovative MDT tool. Themodular design of the MDT tool enablesit to be configured on site to accom-plish specific PVT measurements andsampling objectives. Different modulesare used to acquire the exact informa-tion required for informed and timelydecision-making.

A power cartridge converts AC powerfrom the surface to DC power for allother modules in the tool.

The reservoir hydraulic power unitcontains an electric motor and hydraulicpump to provide power for setting andretracting the probe modules.

The single-probe module containsthe probe assembly (with packer andtelescoping backup pistons), pressuregauges, fluid resistivity and temperaturesensors, a pretest chamber, a straingauge, and a high-resolution CQG*Crystal Quartz Gauge.

The dual-probe module contains twoprobes mounted diametrically oppositeeach other. Combining the single- anddual-probe modules forms a systemcapable of determining horizontal andvertical permeability.

Sample chambers are available inseveral sizes and are manufactured forstandard and hydrogen sulfide service.Electromechanically actuated throttle-seal valves, controlled from the surface,direct the samples to any chamber.

The multisample unit allows the collection of high-quality PVT samples.Its sample chambers detach easily fortransport to a PVT laboratory withoutwellsite transfer.

The pumpout unit pumps unwantedfluid from the formation to the bore-hole so that representative samples can be taken.

The LFA* Live Fluid Analyzer incor-porates an absorption spectrometer toquantify the amounts of reservoir anddrilling fluids in the MDT tool flowlineand a gas refractometer to differentiategases and liquids.

A packer assembly uses two inflatablepackers set against the borehole wall toisolate a 3- to 11-ft interval of the forma-tion. This module provides access to theformation over a wall area that is thou-sands of times larger than a typical for-mation tester probe.

The flow-control module is a 1,000-cm3

chamber in which flow rate is accuratelymeasured and controlled.

Powercartridge

Live FluidAnalyzer

Hydraulicmodule

Single-probemodule

Sample chambers

Multisamplemodules

Pumpoutmodule

Composition Fluid Analyzer

The MDT tool and its modules enable real-timedetermination of PVT properties and high-qualitysample collection. This schematic shows onepossible configuration.

FE_03_003_0 ©Schlumberger

March 2004 *Mark of Schlumberger

www.slb.com/oilfield

CFA Module Specifications

Length with handling caps 79 in. [200.7 cm]Makeup length 61 in. [154.9 cm]Diameter 4.75 in. [12.1 cm]Weight 161 lbm [73 kg]Pressure rating 20,000 psi [1,379 bar]Temperature rating 350°F [175°C]Tensile strength 50,000 lbf [22,680 kg]Measurement accuracy

Composition ±10% (partial density)GOR ±20% (1,000 to ~20,000 scf/bbl)Fluorescence ±1 nW