Composición CFA

CFA Composition

Fluid Analyzer

Expanded technology for gas sampling and analysis

Downhole fluid analysis by the CFA* Composition Fluid Analyzer module of the MDT Modular Formation Dynamics

Near-infrared optical absorption spectrometry and fluorescence emission measurements are used to determine gas-fraction concentrations and to identify fluid types, respectively, as fluids flow through the CFA module.

composition by depth

■ Monitoring changes in fluid composition due to injection or production

■ Downhole determination of reservoir architecture, including layer connectivity

Tester ensures recovered samples are rep-

resentative—one of the reasons the MDT tool is the industry standard for acquir- ing reservoir fluid samples on wireline.

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

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

■ methane (C1)

■ ethane-propane-butane-pentane

Fluorescence detector

Sample flow

RF CH 470 nm

FL CH#1 >550 nm

FL CH#2 >680 nm

Light source 470 nm

The importance of accurate fluid sampling and analysis

Lamp

Spectrometer

(gas analyzer)

Benefits

■ Representative samples (single-phase, acceptable level of contamination)

■ Minimal time required for sample acquisition

■ Early determination of GOR

or CGR for reservoir valuation

■ Determination of fluid compositional gradient for reservoir modeling

■ Early determination of layer connectivity for completion

(C2–C5)

■ heavier hydrocarbon molecules (C6+)

■ H2O

■ CO2.

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

The CFA module also measures fluorescence emission to identify fluid type and to ensure that samples are acquired above the dewpoint for a

gas condensate.

Accurate determination of in situ sample

properties is essential, not only to char- acterize and produce a reservoir, but also to design well completions, subsea tiebacks, and topside facilities. Reservoir fluids composition, phase behavior, and flow assurance (solids deposition) are routinely measured by a pressure-volume- temperature (PVT) laboratory such as Oilphase-DBR, the world’s leading pro- vider of PVT laboratory services.

decisions

Features

■ Quantitative weight-percent measurements of hydrocarbon, water(H2O), and carbon dioxide (CO2)

■ Real-time contamination monitoring for sampling

in wells drilled with oil-base

Shown here are optical absorption spectra for C1, C2–C5, C6+, and CO2 compounds. The absorption spectrum

for 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.

2.0

1.5

mud and deciding when to sample

■ Measurement of fluorescence emission

■ Measurement of light absorption at selected wavelengths

■ Efficient integration with all other MDT* Modular Formation Dynamics Tester modules

Optical density

(path length = 2 mm)

1.0

0.5

0.0

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

Wavelength (nm)

Downhole reservoir fluid analysis provides assurance that captured sam- ples are representative. Since the CFA module identifies fluid properties in real 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 liquid phase. Hydrocarbon gases can be dry, wet, or condensate (alternatively catego- rized as dry, lean, or rich). Dry gas will not precipitate liquid during sampling downhole nor at surface separator con- ditions. Wet gas cannot precipitate liq- uid during downhole sampling, but it

will precipitate small amounts at sur-

will precipitate as liquid condensate at surface temperature and pressure con- ditions. The CFA measures the compo- sition of the condensate while it is still in the gas phase. This vaporized com- position is the C6+ fraction. From the ratio of the C6+ fraction to the C1–C5 fraction, the CGR is determined. CGR indicates the condensate yield, or the barrels of liquid that will condense from

1 million scf of gas at standard tempera- ture and pressure conditions.

Fluid identification from fluorescence emission data

The CFA module measures fluorescence emission using a narrow-spectrum light

The fluorescence emission spectrum varies with the amount of condensate vaporized in the gas; the spectrum is reduced whenever the pressure of a condensate falls below its dewpoint. Therefore, the spectrum can be moni- tored to ensure the reservoir fluid is sampled above its dewpoint.

Information to optimize production

The 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 different fluids, downhole evaluation of CO

face temperature and pressure. Gas con-

densate will precipitate a liquid phase downhole if the flowing pressure goes below its dewpoint.

Fluid composition answers from optical absorption spectrometry data

source, a blue-light-emitting diode. The light is absorbed by the fluid in contact with the window on the flowline of the tool and is then reemitted as a wide spectrum of longer wavelengths.

2

level, downhole determination of dew-

point, secondary recovery monitoring, and oil-base mud sampling.

The CFA module contains an optical absorption spectrometer that uses visi- ble and near-infrared light to quantify a fluid’s composition as it flows through the tool. The spectrum of light is trans- mitted through the fluid to an array of detectors tuned to selected wavelengths. The amount of light absorbed by the fluid depends on its composition. The measured absorption spectrum is rep- resented as a linear combination of the unique absorption spectra for C1, C2–C5, C6+, CO2, and H2O, allowing determi- nation of the weight percent of each molecular group.

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

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

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

100

100

100

100

80 80 80 80

Tool 60 60 60 60

estimation

(wt %)

40

20

0

0 20 40 60 80 100

40

20

0

0 20 40 60 80 100

40

20

0

0 20 40 60 80 100

40

20

0

0 20 40 60 80 100

True mass fraction (wt %)

True mass fraction (wt %)

True mass fraction (wt %)

True mass fraction (wt %)

Fluid scanning for a compositional gradient in a thick reservoir

Fluid scanning refers to the evaluation of reservoir fluids at a large number of depths using the combination of down-

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.

hole analysis and a short pumpout period available with the MDT sampling string. No fluid sampling is required. In a thick gas reservoir, CFA scanning can be used to measure the compositional gradient of the reservoir fluid.

Identification of layers with different fluids

Even using logs and seismic data, it can be difficult to

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