Downhole Sampling

8/10/2019 Downhole Sampling

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4 Oilfield Review

Focusing on Downhole Fluid Samplingand Analysis

Ridvan AkkurtSaudi Aramco

Dhahran, Saudi Arabia

Martin Bowcock

BG GroupReading, England

John DaviesChevron

Houston, Texas

Chris Del CampoSugar Land, Texas, USA

Bunker Hill

Rosharon, Texas

Sameer Joshi

Dibyatanu KunduMumbai, India

Sanjay KumarCairn Energy India Pty Ltd

Gurgaon, India

Michael OKeefeHobart, Tasmania, Australia

Magdy SamirAberdeen, Scotland

Jeffrey TarvinCambridge, Massachusetts, USA

Peter WeinheberHouston, Texas

Stephen WilliamsHydro

Bergen, Norway

Murat ZeybekAl-Khobar, Saudi Arabia

For help in preparation of this article, thanks to StephaneBriquet, David Nunez and Ricardo Vasques, Sugar Land,

Texas; Kre Otto Eriksen, Statoil ASA, Stavanger;Noriuki Matsumoto, Sagamihara, Kanagawa, Japan; MoinMuhammad, Edmonton, Alberta, Canada; Oliver Mullins,Houston; Tribor Rakela, Caracas; John Sherwood, Cambridge,England; and Dag Stensland, ENI Norge, Stavanger.Thanks also to ConocoPhillips (UK) Ltd.

CFA (Composition Fluid Analyzer), InterACT, LFA (Live FluidAnalyzer), MDT (Modular Formation Dynamics Tester),MRX (Magnetic Resonance eXpert), Quicksilver Probe,Platform Express, PVT Express and SlimXtreme are marksof Schlumberger.

A new focused-sampling device allows acquisition of downhole fluid samples of

unprecedented purity, and in a fraction of the time needed with conventional sampling

technology. The method also gives superior results for downhole measurements of

formation-fluid properties.

Understanding the properties of fluids contained

in a hydrocarbon reservoir requires measure-

ments on fluid samples. Sample analysis helpsidentify fluid type, estimate reserves, assess

hydrocarbon value and determine fluid

properties, so production can be optimized.

Using fluid-analysis results, oil companies decide

how to complete a well, develop a field, design

surface facilities, tie back satellite fields and

commingle production between wells.

Fluid analysis is also important for under-

standing the properties of formation water,

which can have significant economic impact.

Often, the most crucial goals are to identify the

corrosive properties of the water for the purpose

of selecting completion materials and to measurescaling potential for avoiding flow-assurance

problems. In addition, log analysts want to

quantify the salinity of the water for petro-

physical evaluation, and geologists and reservoir

engineers want to establish the water source for

evaluation of reservoir connectivity.

Formation-fluid samples can be acquired

using one of three main techniques. First,

wireline formation testers deployed in open hole

can acquire fluid samples and also perform down-

hole analysis of fluids, ensuring optimal sample

acquisition and the possibility of analyzing fluids

early in the life of the well. These testers providea cost-effective method of acquiring early fluid

samples, with performance now often equal to or

above that achievable with the second method,

drillstem tests (DSTs). In the past, DSTs,

typically designed to test production and investi-

gate reservoir extent, have produced samples

with less contamination than openhole sampling.

DSTs require early planning and a well comple-

tion that can withstand production pressures,

and can cost much more than openhole

sampling, especially in offshore wells. In a thirdmethod, samples can be acquired by wireline

tools deployed in a cased, producing well.

An important aspect of fluid sampling is

analysis of the fluids at reservoir conditions. This

helps validate sample quality during the sampling

process, but also enables the mapping of vertical

variations in fluid properties, allowing inter-

preters to determine zonal connectivity and

define reservoir architecture early in field life.

Uncontaminated fluid samples allow accurate

measurement of fluid properties both downhole

and at the surface.

After samples are acquired, they typically areanalyzed in laboratories, where they undergo a

series of tests depending on what the client

needs to understand. Standard analyses for

hydrocarbon samples include chemical composi-

tion to C30+, gas/oil ratio (GOR), density, viscos-

ity, and phase properties such as saturation

pressure, bubblepoint, pour point and stability of

asphaltenes.1 Several measurements can now be

performed downhole, using optical spectroscopy

to characterize formation fluids under reservoir

conditions.2 These include density, optical

density, GOR and chemical composition to C6+.

Laboratory and downhole fluid measurementsboth require pure, uncontaminated samples.

Contamination occurs when miscible drilling-

fluid filtrate that has invaded the formation

mixes with the formation fluid being sampled.

For instance, hydrocarbon samples are contami-

nated by oil-base mud (OBM) filtrate, and water

samples are contaminated by water-base mud

(WBM) filtrate.


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1. The phrase composition to C30+ indicates thatcompounds of up to 29 carbon atoms are separatelydiscriminated, with the remainder combined into afraction indicated as C30+.

Pour point is the minimum temperature at which oilpours or flows.

2. Fujisawa G, Betancourt S, Mullins OC, Torgersen T,OKeefe M, Terabayashi T, Dong C and Eriksen KO:Large Hydrocarbon Compositional Gradient Revealedby In-Situ Optical Spectroscopy, paper SPE 89704,presented at the SPE Annual Technical Conferenceand Exhibition, Houston, September 2629, 2004.

3. Mullins OC, Schroer J and Beck GF: Real-TimeQuantification of Filtrate Contamination During OpenholeWireline Sampling by Optical Spectroscopy,Transactions of the SPWLA 41st Annual LoggingSymposium, Dallas, June 47, 2000, paper SS.

Mullins OC and Schroer J: Real-Time Determination ofFiltrate Contamination During Openhole WirelineSampling by Optical Spectroscopy, paper SPE 63071,presented at the SPE Annual Technical Conference and

Exhibition, Dallas, October 14, 2000.Dong C, Mullins OC, Hegeman PS, Teague R, Kurkjian Aand Elshahawi H: In-Situ Contamination Monitoring andGOR Measurement of Formation Fluid Samples, paperSPE 77899, presented at the SPE Asia Pacific Oil andGas Conference and Exhibition, Melbourne, Australia,October 810, 2002.

4. Gozalpour F, Danesh A, Tehrani D-H, Todd AC andTohidi B: Predicting Reservoir Fluid Phase andVolumetric Behaviour from Samples Contaminated withOil-Based Mud, paper SPE 56747, presented at theSPE Annual Technical Conference and Exhibition,Houston, October 36, 1999.

Winter 2006/2007 5

To reduce contamination during sample

collection, engineers rely mostly on increasing

the volume of fluid pumped from the reservoir by

pumping longer or at a higher rate. Downhole

analysis of contamination level can determine

when fluid flowing through the sampling-tool

flowline is clean enough to be collected.3

However, long pumping time increases rig time

and associated costs, and may increase the risk

of downhole tool sticking. Depending on the

reservoir permeability, high pumping rates can

cause the reservoir fluid to drop below saturationpressure. If this happens, the downhole samples

will not be representative of the reservoir fluid.

In the case of unconsolidated formations, high

pumping rate may induce sand production. Also,

in settings involving high vertical permeability,

even long pumping times and increased pumping

rates do not guarantee clean samples.

Fluid-analysis experts have worked to under-

stand and mitigate the effects of contamination

on samples. Some methods attempt to derive the

composition or GOR of a pure sample knowing

the composition of the OBM contaminating the

collected sample.4 However, uncertainties and

errors accompany fluid properties estimated in

this manner. Researchers have quantified the

errors caused by contamination on some

measurements. For example, the pressure a

which asphaltenes precipitate from solution in

crude oil decreases in the presence of OBM

contamination. In one case, just 1% OBM

contamination by weight caused asphaltene


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precipitation onset pressure to decrease by

100 to 150 psi [0.7 to 1.0 MPa] (left).5 Thus,

measurements on contaminated samples under-

estimate asphaltene-precipitation onset pressure,

and may negatively affect flow-assurance and

production predictions. These results emphasize

the need for extremely low-contamination samples.

A new sampling apparatus designed to reduce

filtrate contamination focuses fluid intake so

that reservoir fluid flows into one sampling line

while filtrate flows into a separate line. With this

innovative tool, mud-filtrate contamination can

be separated efficiently from formation fluid in

the early stage of the sampling process. A clean

reservoir-fluid sample can be acquired much

faster than with conventional sampling tech-

niques. This article describes the advantages of

the new, focused-sampling tool through field

examples of hydrocarbon and water sampling

from the Gulf of Mexico, the North Sea, India and

the Middle East.

Quicker and CleanerTo fully appreciate the advantages of the new

sampling method requires a brief overview of

conventional downhole fluid-sampling technology.

In the typical scenario, overbalanced drilling into

a permeable formation will facilitate invasion of

drilling-fluid filtrate into the formation and the

creation of filtercake on the borehole wall.

During conventional formation-fluid sampling, a

wireline formation tester deploys a packer

against the borehole wall to isolate the sample

probe from borehole fluids and hydrostatic

pressure. The probe is then pressed through the

mudcake and against the formation (left). Asuccessful seal connects the sampling tool with

the formation while isolating the tool flowline

from borehole fluid and pressure.

As the sampling tool withdraws fluid from the

formation through the probe, the first reservoir

fluid to enter the flowline is contaminated with

filtrate from the drilling fluid. The level of

contamination, monitored in real time by

downhole spectroscopic analyzers, decreases as

pumping continues. Depending on formation

permeability, anisotropy, amount of invasion,

formation-fluid viscosity, and pumping time, rate

and pressure drawdown, the contamination levelmay or may not decrease sufficiently to allow

collection of a fluid sample that is representative

of the formation fluid. Filtrate contamination

from deeply invaded zones may continue to feed

into the sampling probe, and in cases of poorly

formed mudcake, borehole fluid may continue to

invade the formation at a relatively significant

rate. Achieving sufficiently low levels of

contamination may require pumping for

6 Oilfield Review

> The effect of oil-base mud (OBM) filtrate contamination on asphaltene-precipitation onset pressure.Laboratory analysis on live oils with varying amounts of added OBM filtrate shows a decrease inasphaltene-precipitation onset pressures with increased OBM contamination. Live oils are oils thatcontain dissolved gas. Asphaltene precipitation is detected by light transmittance; precipitates scatterlight and decrease transmittance. These and similar experiments show on average that for 1% byweight OBM contamination, asphaltene onset pressure decreases by 100 to 150 psi. The 19.4%contamination sample reached saturation pressure before it reached the asphaltene-precipitation

pressure. (Adapted from Muhammad et al, reference 5.)

Saturationpressure

Asphaltene-precipitationonset pressures

Contamination(live-oil basis)

2.6 % by weight

7.6 % by weight

14.2 % by weight

19.4 % by weight

Pressure

Powero

ftransm

itte

dlig

ht

5. Muhammad M, Joshi N, Creek J and McFadden J:Effect of Oil Based Mud Contamination on Live FluidAsphaltene Precipitation Pressure, presented at the5th International Conference on Petroleum PhaseBehaviour and Fouling, Banff, Alberta, Canada,June 1317, 2004.

6. Sherwood JD: Optimal Probes for Withdrawal ofUncontaminated Fluid Samples, Physics of Fluids17,no. 8 (August 2005): 083102.

7. Tarvin JA, Gustavson G, Balkunas S and Sherwood J:Sampling Fluid from a Two-Dimensional Porous MediumWith a Guarded Probe, submitted to Journal ofPetroleum Science and Engineering.

> Conventional formation-fluid sampling with a wireline formation tester.The tester forces a packer to seal against the borehole wall, then pressesa probe through the mudcake and against the formation (right). Formationfluid is blue-gray and filtrate is light brown. The probe (left) has a singleintake port. When pumping begins, fluid is highly contaminated (graph

inset), but decreases gradually with time. However, even with longpumping times, the contamination level may not reach an acceptable limitin some formations.

Contaminationlevel

Time

Acceptable sample


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Winter 2006/2007 7

extended periods of timemany hourswhich

can be expensive in terms of rig time and

increased exposure to sticking in open hole.

Seeking ways to improve sample quality andreduce sampling time, researchers investigated

the effects of different probe configurations.

To test the idea that focused flow into a probe

could reduce sample contamination and shorten

sampling time, a scientist at Schlumberger

Cambridge Research in England simulated flow

into modified probes.6 The modeling results

helped determine optimal probe size.

Researchers at Schlumberger-Doll Research in

Connecticut, USA, conducted 2D experiments on

laboratory models to determine the potential

benefits in sample cleanup (above).7 The

modified probes had three openings: side open-ings, called guard probes, drew contaminated

fluid away from the central area of the probe, and

a central opening, called a sample probe,

collected low-contamination fluid. Experimental

results indicated that cleanup with the guard

probes active proceeded much more quickly than

without, achieving lower contamination levels

with less fluid volume pumped (right).

A

B

C

D

Without Guard

A

B

C

D

With Guard

> Setup and visual results of laboratory experiments simulating focusedflow. The experimental setup (top right) consisted of a 2D formation madeof glass beads, surrounded by a single oil with an optical index identical

to that of the glass beads, all held between two vertical glass plates. Abottom portion of oil was dyed red to represent the filtrate-invaded zone.Above this, the oil was left transparent. A sample and guard-probeassembly at the bottom of the formation extracted fluid ( inset). A cameramonitored the cleanup in the formation directly in front of the probeassembly. After image processing, the time-lapse visual images (left) showlarge differences in the area cleaned up by the sample probe alone ( left)and the sample and guard probes together (right). The sample and guardprobes clean up a large area in front of the sample probe, ensuring thatonly uncontaminated fluid enters the sample probe.

> Contamination reduction with and without guard probes. Laboratorymeasurements detected decreasing contamination levels with increasingvolume of fluid pumped, corresponding to increasing pump time. Samplingwithout the guard probe (blue) never achieved contamination levels lessthan 1%.

Dyeconcentration

,%o

fmaximum

100

10

1

0 20 40 60 80 100 120 140 160 180 200

Volume pumped, ml

Without guardWith guard


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8 Oilfield Review

> Engineering experimental setup to investigate the feasibility of focused sampling. Aformation interface tester, containing a 15.5-in. diameter, 12-in. tall sandstone core, is incontact with two fluid manifolds and a laboratory-prototype focused-sampling probe.

Simulated formation fluid is supplied at the base of the core, and simulated filtrate issupplied in a ring around the core. Flow into and from the tester is controlled andmonitored by pumps and valves, and contamination level is calculated from electricalconductivity measurements on the flowlines. (Adapted from Dong et al, reference 8.)

Formation and filtrate fluid(supply side)

Sampling and conductivity(measurement side)

Accumulators

Meteringvalves

Meteringvalves

Flowmeters

Flowmeters

Conductivitymeters

> Focused-sampling experimental data. The decrease in contamination inferred fromelectrical conductivity measurements on the guard and sample flowlines demonstratesfluid cleanup in this sampling test. The contamination level in the sample flowline (green)decreased rapidly, while the contamination level in the guard flowline (red) decreasedgradually. Summing the flow from both flowlines produces the total flow (blue), the flowthat a traditional probe would have measured. (Adapted from Dong et al, reference 8.)

Contam

ination

,%

10

20

0

30

40

50

60

70

80

90

100

10 0 10 20 30 40 50 60

Elapsed time, min

Guard flowline

Total flow

Sample flowline

Further engineering tests at Sugar Land

Technology Center in Texas extended the 2D

results in simulated formations to three

dimensions and actual rock formations. In these

experiments, a downhole probe prototype of a

new focused-sampling tool drew fluids from a

large sandstone core in a test apparatus (left).8

The 15.5-in. diameter, 12-in. tall core contained

aqueous sodium chloride [NaCl] formation fluid

and mud-filtrate fluid of different known

conductivities. Fluid flow to the guard and

sample flowlines was controlled and measured

with meter ing valves and high-pressure

flowmeters. Calibrated electrical conductivity

meters on the flowlines leading from the guard

probe and the sample probe recorded the

cleanup history of each sampling test. With

focused sampling, the contamination levels of

the fluid in the sample flowline decreased

rapidly, while the contamination level in the

guard flowline decreased gradually(below left).

A traditional probe would have measured the

combined flow, and would not have achievedcontamination less than 10%.

The key to acquiring such low-contamination

samples is the focusing effect achieved by the

multi-intake probe.9 This innovative design has

been implemented in the Quicksilver Probe

wireline sampling tool, a new module of the MDT

Modular Formation Dynamics Tester tool. In

some ways, the configuration of the Quicksilver

Probe module is similar to that of traditional

samplers, in that a packer seal isolates the fluid-

sampling zone from the borehole. However,

within the fluid-sampling zone, a cylindrical

guard probe on the periphery of the samplingzone surrounds the innermost sampling area

(next page, left). An additional packer seal

separates the guard intake from the sample

intake. The inner and peripheral areas are

connected to separate flowlines, called the

sample and guard flowlines, respectively. Two

pumps in the tool, one above the probe and one

below, can draw fluid into the two flowlines at

different rates, and spectroscopic analyzers

determine the composition of fluid in each

flowline (next page, right). The focusing effect of

the method is somewhat analogous to the way

laterolog devices use guard electrodes to focuscurrent into a formation to measure resistivity.10

The Quicksilver Probe focused-sampling tool

pumps fluid from the formation through the

central and peripheral areas of the sampling

zone simultaneously. Initially, commingled con-

taminated fluid flows into both areas, but this


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Winter 2006/2007 9

fluid is not collected. Fluid flow is then

separated, or split, between the guard and

sample flowlines. Fluid flow into the guard intake

can be increased, and in a short time, all

contaminated fluid is drawn into the guardflowline, allowing low-contamination formation

fluid to flow into the sample flowline. This

technique accentuates the difference in contam-

ination level between clean and contaminated

fluid, making it easier to identify a time at which

a clean sample can be collected. Case studies

from several environments show the sample

quality that can be obtained using the new

focusing technology.

Exploring in the Gulf of Mexico

In 2004, Chevron drilled an exploration well into

the emerging Lower Tertiary play in thedeepwater Gulf of Mexico. These wells are

typically difficult to drill and complete, with

water depths down to 10,000 ft [3,000 m] and

total well depths exceeding 25,000 ft [7,600 m].

More than 20 exploration and appraisal wells

have been drilled so far in this play, and more

than half were discoveries, many with thick oil

columns. However, in such conditions, well tests

usually are extremely expensive, typically costing

US$ 70 million or more. For this reason DSTs are

rarely performed in this region.

Drilling in this play in Walker Ridge Block759, Chevron and partners announced discovery

of more than 350 ft [110 m] of net-pay oil sands

in Jack 1, the first well of the Jack prospect, in

September 2004.11 The subsalt prospect is

8. Dong C, Del Campo C, Vasques R, Hegeman P andMatsumoto N: Formation Testing Innovations for FluidSampling, presented at the Deep Offshore TechnologyConference and Exhibition, Vitoria, Espirito Santo, Brazil,November 810, 2005.

9. Del Campo C, Dong C, Vasques R, Hegeman P andYamate T: Advances in Fluid Sampling with FormationTesters for Offshore Exploration, paper OTC 18201,presented at the Offshore Technology Conference,Houston, May 14, 2006.

10. Doll HG: The Laterolog: A New Resistivity LoggingMethod with Electrodes Using an Automatic FocusingSystem, Petroleum Transactions of the AIME192 (1951):305316.

11. ChevronTexaco Announces Discovery in Deepwater Gulfof Mexico, http://www.chevron.com/news/press/2004/2004-09-07.asp (accessed September 22, 2006).

>

Formation-fluid sampling with the Quicksilver Probe focused-sampling tool. The probe(left) has two intake ports, with the guard intake surrounding the sample intake. Packerssurround and separate these probes and seal against the borehole wall ( right).Formation fluid is blue-gray and filtrate is light brown. When pumping begins, fluidflowing through the sample intake is highly contaminated (graph inset), but decreasesquickly with time. Soon, contamination levels are at an acceptable value.

Contaminationlevel

Time

Acceptable sample

> The Quicksilver Probe toolstring. Fluids enterthe tool at the focused-sampling probe.Contaminated fluids flow downward through theguard fluid analyzer and pump. Clean fluids flowupward through the sample fluid-analyzer andpump modules to the sample-bottle module. Theconfiguration may change for different samplingjobs. For example, the pumps may be locatedupstream of the fluid analyzers for someapplications. (Adapted from Del Campo et al,reference 9.)

Power cartridge

Sample-bottlemodule

Sample pumpmodule

Sample fluidanalyzer

Hydraulic module

Focused-samplingprobe

Guard fluidanalyzer

Guard pumpmodule


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10 Oilfield Review

approximately 270 miles [430 km] southwest of

New Orleans and 175 miles [280 km] offshore (right).

To further evaluate the prospect, Chevron

drilled a second well, Jack 2, in Walker Ridge

Block 758 to a total depth of 28,175 feet

[8,588 m]. Departing from typical procedures,

Chevron planned a well test, which would make

Jack 2 the only Lower Tertiary well ever tested in

the Gulf of Mexico. Acquiring a pure sample of

the formation fluid prior to the production test

would aid significantly in reducing the fluid

uncertainties in the test design and therefore

enhance the value of this expensive endeavor.

A unique MDT sampling toolstring config-

uration allowed collection of traditionally

acquired fluid samples at two stations with an

extralarge-diameter (XLD) probe, and focused

samples at two stations with the Quicksilver Probe

module.12 Real-time analysis of flowline fluid

acquired at one station with the XLD probe shows

GOR increasing but not leveling off, even after

8 hours of pumping (below left). Nevertheless,

samples were collected at 30,000 seconds.> The Lower Tertiary play in deepwater Gulf of Mexico, where Chevron discovered the Jack fieldin 2004. Other wells in the Lower Tertiary play are shown as dots.

S A L T

HoustonNew Orleans

G U L F O F M E X I C O

Jack

km

miles0

0 150

150

> Cleanup plot of flowline fluid acquired with asingle extralarge-diameter probe in the ChevronJack 2 well. The volume of fluid pumped duringsampling is shown in the top track. Real-time

analysis of optical density measured with the LFALive Fluid Analyzer tool leads to quantification ofthe volume fraction of C6+ components,essentially liquid hydrocarbons (second track),and gas/oil ratio (GOR) (third track) as flowlinefluid becomes cleaner. GOR (blue) continues toincrease, indicating cleaner sampling, but doesnot level off, even after 8 hours of pumping.Laboratory analysis of samples collected at30,000 seconds showed the contamination levelto be greater than 10%. A data-quality flag track(bottom track) is green when data quality is high,and brown when data quality is lower.

0

Vo

lume

fracti

on

1.0

0.5

0

GOR

0 5,000 10,000 15,000 20,000 25,000 30,000

Startpumping

Elapsed time, s

200,000

100,000

Pumpoutvo

lume

,cm

3

> Pumpout volume, volume fraction and GOR plots for sample-line (left) and guard-line (right) fluidsobtained with Quicksilver Probe focused sampling. As seen in the pumpout-volume track (top), onlythe guard-line pump (red) operates from 0 to 7,340 s. Then, the sample-line pump (brown) is activatedand pumps until 11,500 s, at which time both pumps operate synchronously but at different rates.Cleanup can be seen by the increase in GOR (blue) in the guard flowline from 0 to 7,340 seconds,while the sample line is idle. Then, the guard pump stops and the sample-line pump starts. The GORseen by the sample-line LFA module increases gradually at first, and then, when flow is split at11,500 s, the sample-line GOR increases dramatically and reaches a plateau, indicating that the fluidis clean. The sample acquired at 14,000 s had a contamination level that was too small to measure.

0 2,500 5,000 7,500 10,000 12,500

Elapsed time, s

15,000

0Pumpoutvo

lume

,cm

3

Vo

lume

fracti

on 1.0

0.5

0

GOR

Startpumping

300,000

100,000

200,000

0 2,500 5,000 7,500 10,000 12,500

Elapsed time, s

15,000

300,000

100,000

0

Vo

lume

fracti

on 1.0

0.5

0

Startpumping

200,000

Pumpoutvo

lume

,cm

3

GOR


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In the UK North Sea, HPHT wells are usuallydrilled with OBM. Conventional wireline fluid

sampling in OBM-drilled wells normally requires

long pumping times. This extended time

increases the chances of tool failure related to

high temperature, and can yield unsatisfactory

samples. Shorter cleanup time and better sample

quality are needed for successful fluid sampling

in HPHT conditions. Some examples from HPHT

wells in the North Sea show how the focusing

action of the Quicksilver Probe tool reduces

cleanup time, minimizing tool exposure to high

temperatures, improving sample quality and

reducing the risk of tool sticking.In one HPHT example from the central North

Sea, ConocoPhillips (UK) Ltd applied new and

proven technologies to overcome difficulties in

this hostile environment. Experience had shown

that in addition to high temperatures and

pressures, wells in the area were prone to sticky

hole conditions; the effects of depth, filtercake

properties, hydrostatic overbalance and wellbore

tortuosity combined to hinder wireline-conveyed

reservoir evaluation. Obtaining any data under

these conditions required assuring the drilling

team that appropriate steps would be taken to

reduce the risk of logging tools becoming stuck in

the hole. Studies were conducted to confirm that

any hydrocarbon fluids pumped into the borehole

during fluid analysis would not destabilize the

mud column. Pipe-conveyed wireline logging was

ruled out for safety reasons.

ConocoPhillips (UK) Ltd had successfully

logged other challenging HPHT wells in the

region with a high-tension logging package. In

these cases, wireline logging tools were lowered

into and raised from the wells using high-strength

cable and a capstan. The capstan, placed between

the drill floor and the wireline unit, increases the

wireline pull from 9,700 to 15,500 lbm [4,400 to7,030 kg], ensuring that even long, heavy tool-

strings can be retrieved.

In this near-field exploration well,

ConocoPhillips (UK) Ltd planned to log the well

and acquire pressures to determine mud weights

for drilling deeper and to characterize the

formation fluid. Sampling would not be required

in the primary reservoir, because the fluids in the

nearby producing fault blocks were known.

Bottomhole temperatures were expected to

reach 365F [185C] and formation pressures

could exceed 14,000 psi [97 MPa]. SlimXtreme

slimhole HPHT logging tools, including the newanalog borehole seismic tool, would be run on

high-strength cable with the capstan unit.

The well encountered an unanticipated

secondary reservoir above the primary target,

introducing uncertainty into the understanding of

fluid properties. The logging program was

immediately modified to include fluid sampling in

these newly discovered zones. A Quicksilver Probe

module was readied to run in the hole and a PVT

Express onsite well fluid analysis system was

installed on the platform to perform surface

analysis of samples collected from the four

new zones.In the first sand sampled using the

Quicksilver Probe focusing device, the tool

operated smoothly, and flow through the tool

began in commingled mode. Flow was split

between the sampling and guard probes after

2,600 seconds of pumping, giving rise to an

abrupt GOR increase from 850 ft3/bbl

[150 m3/m3] to around 1,500 ft3/bbl [270 m3/m3]

(left). GOR leveled off at 1,550 ft3/bbl

[279 m3/m3] and remained high while samples

were collected. Initial wellsite fluid analysis

showed high-purity oil. Final onshore laboratory

results found contamination to be 1%.

PVT Express fluid-analysis experts on site

identified 600 to 900 ppm of hydrogen sulfide

[H2S] in the shallowest sand layer, which would

be incompatible with the completion design.

These levels of H2S in the first sandstone led the

ConocoPhillips (UK) Ltd subsurface team to

upgrade their scrutiny of the other unexplored

layers. Additional tool runs were scheduled for

the remaining sandstone intervals in the 8-in.

section, including many more sampling stations,

assuming the Quicksilver Probe module could

withstand the high temperatures.

At another station, Quicksilver Probe opera-

tion began and remained with the tool bypass

valve in the open position. This means that the

guard and sample flowlines were hydraulically

connected inside the tool, mimicking traditional,single-probe sampling. Pumping continued for

more than 14,000 secondsabout 4 hoursat

which point samples were collected, because the

fluid was not getting any cleaner (next page,

top). Wellsite analysis determined contamination

to be 22%, which was confirmed by the onshore

laboratory result of 23% three weeks later.

Before moving away from this sampling

station, the field engineer managed to close the

bypass valve and establish focused flow. Fluid

flow split into the guard and sampling flowlines,

GOR increased dramatically, and contamination

decreased. PVT Express onsite analysis indicatedthat contamination levels fell from 22% to 1.5%.

The fluid samples collected here showed 1%

contamination in later laboratory analysis.

Normal levels of H2S were found here and in the

remaining layers. In all, 27 fluid samples were

acquired with good-quality results in every layer.

The well was subsequently completed,

perforating only those layers that had been shown

to have low H2S levels compatible with the tubing

metallurgy. Being able to acquire a suite of

uncontaminated downhole samples as part of a

rapidly evolving logging program was vital to the

success of the development of this secondaryreservoir. If high-quality samples had not been

taken and the well completion had proceeded

without this data, high concentrations of H2S

would have damaged the production tubing and

entered the production facility. Mitigating that

would have required shutting in production and

performing a costly well workover to identify and

shut off the H2S-prone zone.

12 Oilfield Review

15. A safety sample is a sample that may be less than ideal,for example, one that is somewhat contaminated, but itis acquired anyway in case the tool fails and no furthersampling is possible.

16. A single-phase sample bottle maintains the single-phasenature of a fluid sample as it is brought to surface.

> Monitoring sample cleanup using the QuicksilverProbe focusing device. At 2,600 seconds, flowwas split between the sample and guard probes,with the guard probe pumping at a higher rate(brown, top track). GOR increased quickly from850 ft3/bbl to around 1,500 ft3/bbl, eventuallyreaching 1,550 ft3/bbl (third track). PVT Expressonsite well fluid analysis showed the oil samplecontains almost no OBM contamination and 600to 900 ppm of H2S. Results from onshore laboratoryanalysis found OBM-filtrate contamination to be1%. The data-quality flag (bottom track) is green,indicating high-quality data.

0

75,000

25,000

Pumpoutvo

lume

,cm

3

Volume

fract

ion 1.0

0.5

0

500

0

GOR

,ft3/bbl

1,000 3,000 4,000 5,000 6,000 7 ,000

Elapsed time, s

2,000

1,000

1,500

50,000


10/16

Winter 2006/2007 13

HPHT Sampling Instead of DST

BG, drilling in another HPHT area of the central

North Sea, made a discovery with multiple

hydrocarbon-bearing zones. This exploration well

was designed not to have a DST, saving costs on

two levels. First, a DST in this region would have

cost US$ 10 to 20 million. Second, additional

savings came from installing a less expensive

completion. A DST would require heavier 978-in.

casing to withstand the pressures of the well test,

and a different well-test tree for supporting the

well -test equipment, total ing an addit ional

US$ 4 million. Also, producing no reservoir fluids

to surface would avoid environmental risks.

Since no DST would be run, it was crucial to

acquire high-purity samples by wireline. To allow

real-time analysis of formation fluids, the

Quicksilver Probe tool was configured with LFA

and CFA Composition Fluid Analyzer modules on

the sample flowline. A PVT Express system

installed on the rig analyzed contamination at

the wellsite. Shore-based experts were able to

participate in logging and sample analysis in realtime through the InterACT real-time monitoring

and data delivery system. By confirming sample

purity at the wellsite, engineers would know if

the quality of the acquired sample was adequate,

or if a new sample was required. BG fluid experts

were hoping for samples with less than 5% OBM

contamination. In addition to hydrocarbon

samples, the tool would acquire water samples if

it could sustain the high temperatures deeper in

the reservoir. Pressures were anticipated to be at

least 13,000 psi [90 MPa], and temperature was

expected to surpass the 350F [177C] stated

limit of LFA and CFA operability.In the first and shallowest hydrocarbon

interval sampled, the temperature was already

340F [171C]. Quicksilver Probe operation

proceeded normally, starting with the guard

probe and sample probe connected through the

inner bypass valve. The upper pump was used to

pump fluid through the sample line. The flow was

split into guard and sample lines after

3,050 seconds of pumping, at which time a jump

in GOR on the LFA plot indicated a significant

decrease in contamination of the fluid in the

sample line (right). Less than two minutes later,

when contamination reached an estimated 10%,the one-gallon sample bottle opened to collect a

safety samplea standard practice in difficult

wells.15 This proved prudent, because soon

afterward, the sampling-flowline pump stalled,

but started again.

Contamination continued to decrease, and

when GOR leveled off, a single-phase sample

bottle was opened, filled and retrieved to

surface.16 PVT Express analysis on the rig

quantified extremely low contamination,indicating that the sample was sufficiently pure,

and the tool could be redeployed to the next

deeper and hotter level. Independent onshore

laboratory testing conducted a few weeks later

detected no contamination in this sample.

Three low-contamination samples were

successfully acquired at the next hydrocarbon-

bearing zone, but after that, mud-check valves in

the sample flowline started to show signs of

plugging. However, the deepest and hottest zone

remained to be sampled. There, at the water-

sampling station, slugs of borehole mud and OBM

filtrate were detected by the LFA module,indicating that unexpected fluid movement was

occurring through the fluid-exit port. After some

time, this movement of fluid from the borehole

had cleared the mud-check valve, and

synchronized pumping to the guard and sample

lines proceeded normallydespite the 361F

[183C] bottomhole temperatureallowing

acquisition of formation-water samples.

> Quicksilver Probe operation in a ConocoPhillips (UK) Ltd North Sea well, with the tool bypass valvein the open position (left). With the guard and sample flowlines hydraulically connected inside thetool, the effect is the same as conventional single-probe sampling. The pumpout-volume track (top)shows only the sample pump operating (blue). Cleanup is gradual, as seen by the slow increase of the

GOR with time (third track). After more than 14,000 seconds, the fluid was not getting any cleaner, sosamples were collected. According to PVT Express wellsite analysis, contamination was 22%. Afterthe field engineer closed the bypass valve (right), fluid flow was split into the guard and samplingflowlines at around 15,500 seconds. Both the sample-line pump (blue) and the guard-line pump(brown) were pumping (top track), with the guard-line pump operating at a higher rate. GOR (thirdtrack) jumped to about 1,500 ft3/bbl, indicating a reduction in contamination. Onsite analysis with thePVT Express system quantified a contamination drop from 22% to 1.5%.

0

25,000

Pumpoutvolume,

cm3

Volumefraction 1.0

0.5

0

500

0

GOR,

ft3/bbl

1,000

50,000

1,500

0 2,500 7,500 10,000 12,500 15,000

Elapsed time, s

5,000

Startpumping

0

25,000

Pumpoutvolume,

cm3

Volumefraction 1.0

0.5

0

500

0

GOR,

ft3/bbl

1,000

50,000

1,500

Elapsed time, s

Startpumping

0 2,500 7,500 10,000 12,500 15,0005,000

> Quicksilver Probe operation in BGs HPHT NortSea well. Before 3,050 s, fluid flowed through thesample-line pump (blue, top track). At 3,050 s, theguard-line pump (brown) and sample-line pumpoperated synchronously, with the guard-line pumoperating at a higher rate. This split the flow,giving rise to an abrupt increase in GOR (blue) at3,050 s (second track). The sample acquired at8,700 s was found to contain no contamination.

0

40,000

20,000

Pumpou

tvo

lume

,cm

3

GOR

2,500 5,000 7,500 10,000 12,50

Startpumping

Elapsed time, s


11/16

Determining OBM contamination level of

water samples downhole relied on interpreting

data from the color channels of the LFA module

(left).17 Borehole mud, OBM filtrate and

formation water each have distinctive signatures

in the visible and near-infrared frequency ranges

measured by the tool. The two water samples

collected at this level contained some OBM

filtrate, but this was not a problem, because the

OBM is immiscible in formation water.

BG estimates savings of up to US$ 24 million

by using the Quicksilver Probe focused-sampling

method instead of a drillstem test to acquire

zero-contamination samples.

Sampling Viscous Oils

Viscous oils can be especially diff icult to sample

using traditional sampling technology. With its

relatively lower viscosity, OBM filtrate flows

preferentially to sampling devices, increasing

sample contamination and often leaving high-

viscosity formation fluids in the formation.

Cairn Energy India Pty Ltd experienced suchproblems acquiring oil samples in their Bhagyam

field in northwest India. The Bhagyam field is

one of 19 fields in the Barmer basin tapping the

high-permeability Fatehgarh sandstone. Oil

reserves in the reservoir are currently estimated

at 1.5 billion bbl [240 million m3].18 Oil properties

vary from field to field within the basin, and oils

within the Bhagyam field exhibit compositional

grading from crest to oil/water contact. With a

better understanding of oil properties, Cairn

plans to optimize field development and surface

facility design.

Bhagyam oils have high wax content, givingthem high pour point and high viscosity at

reservoir temperature. Acquiring representative,

PVT-quality samples has been a challenge.19

Before the arrival of focused-sampling tech-

nology in India, most samples acquired by

Schlumberger and other service companies using

traditional openhole formation testers were too

contaminated to yield correct PVT properties

during laboratory analysis.20

To obtain contamination-free samples, Cairn

had resorted to collecting samples from cased

wells using monophasic wire line-deployed

samplers. Samples acquired in this way may havelow levels of contamination, but can be collected

only after the well has been completed.

In a campaign designed to improve sample

quality, the Quicksilver Probe device collected

samples in two Bhagyam wells.21 Of the

18 samples acquired, 15 were of PVT quality. Six

of these showed no contamination. One such

14 Oilfield Review

> Detecting OBM contamination in water samples using the LFA module in the BG HPHT North Sea well.The top track shows quartz-gauge pressure and strain-gauge pressure along with unscaled resistivity(pink) and pump strokes (blue and green). The second track shows volume fraction of C6+ components,indicating OBM-filtrate contamination (green), OBM and solids (red) and water (blue). At 2,600 s, soonafter the guard and sample pumps start to pump synchronously, the sample line receives formationwater (blue). The third track contains the 10 LFA optical channels. Channel 0 (black) detects methane.Channels 6 and 9 (darker blues) detect water. The volume-fraction track detects water (blue) when LFAchannels 6 and 9 reach high amplitudes.

0

6

9

LFA

OpticalChannels

0

1.0

Volume

Fraction

Pressure

Time, s

1,000 2,000 3,000 4,000

Strain-gauge pressure

Quartz-gauge pressure

> Composition from laboratory analysis of viscous-oil samples acquired for Cairn Energy India inthe Bhagyam field in the Barmer basin. Samples, all from the same location, were collected usinga monophasic wireline (WL) sampler in cased hole (green), a conventional wireline formation testerin open hole (blue) and Quicksilver Probe focused sampling in open hole (red). The conventionalwireline formation tester yielded a contaminated sample, while the openhole sample acquired usingthe focusing method compared favorably with the one obtained in cased hole.

Mo

lecompositions

100

10

1.0

0.10

0.01

Contaminationweight %, 39.5

Uncontaminated sample, WL

Contaminated sample, 1035 Well A

Well 1, Quicksilver Probe sample

Hydro

gen

Carbo

ndiox

ide

Metha

ne

Propa

ne

n-Buta

ne

i-Pen

tane

Hexa

nes

Benze

ne

Hepta

nes

Tolue

ne

Ethyl-

benze

ne

Ortho

-xylen

e

Tri-M

e-ben

zene

Unde

cane

s

Tride

cane

s

Penta

deca

nes

Hepta

deca

nes

Nona

deca

nes

Hene

icosa

nes

Trico

sane

s

Penta

cosa

nes

Nona

cosa

nes

Hepta

cosa

nes

Hentr

iacon

tanes

Tritri

acon

tanes

Penta

triaco

ntane

s

I N D I A

RajasthanPAKIS

TA

N

NEPAL

C H I N A

BANGLADESH

SRI LANKA

Barmer Basin

km

miles0

0 500

500


12/16

Winter 2006/2007 15

sample was analyzed for chemical composition

and compared with a sample acquired at the

same location by a traditional openhole formation

tester and one obtained in cased hole (previous

page, bottom). The traditional openhole method

produced a sample that was clearly contaminated

with several OBM components. The sample

acquired in cased hole showed an overall

composition that was similar to the uncontam-

inated Quicksilver Probe sample, with small

concentration variations in a few components.

Following the successful acquisition of

contamination-free samples and the availability

of detailed fluid PVT data, Cairn has better fluid-

property data for carrying out field-development

studies that involve reserves estimation,

facilities design and flow assurance. These

studies will make a significant contribution to

production at Bhagyam and demonstrate the

potential for improved field-development

studies worldwide.

Sampling in Mature FieldsThe Quicksilver Probe device is also a valuable

tool for evaluating the efficiency of hydrocarbon

recovery in mature fields. Examples from

complex, mature fields in the Middle East show

how focused sampling acquired pure samples in

high- and low-permeability formations and

helped assess gas-sweep efficiency.

The first well is in a reservoir that is under

gas-cap expansion drive and water drive.

Recently, several evaluation wells were drilled to

monitor sweep efficiency. The wells were drilled

with OBM and logged with the Platform Express

integrated wireline logging tool and nuclearmagnetic resonance tools for openhole analysis.

The Quicksilver Probe module of the MDT tool

was used to collect fluid samples.

The objective was to evaluate the efficiency of

the gas-cap expansion in the main reservoira

heterogeneous sandstone formation with perme-

ability exceeding 1 darcy. Although low oil

saturations from MRX Magnetic Resonance

eXpert measurements indicated highly efficient

sweep of the oil by expansion of gas, the

formation tester was run to confirm that there

was no mobile oil in the swept zone. The

identification of any remaining mobile oil would

indicate incomplete sweep. The Quicksilver

Probe module identified and sampled fluids at

four stations in the gas zone and one station in

the oil column (below). All zones show the

characteristic increase in GOR when flow

through the guard line is split from the sample

line. Several gas samples were captured with no

OBM-filtrate contamination and with no mobile

oil, indicating highly efficient recovery.

In the oil zone, the GOR measured by the LFA

module was within 1% of the GOR already known

for the field. The pumping time required for a

clean oil sample in this zone was about 1,600

seconds, roughly one-third of the time normally

17. Betancourt S, Fujisawa G, Mullins OC, Carnegie A,Dong D, Kurkjian A, Eriksen KO, Haggag M, Jaramillo ARand Terabayashi H: Analyzing Hydrocarbons in theBorehole, Oilfield Review15, no. 3 (Autumn 2003):5461.

18. Wireline Sampling Technology Enables Fluid SamplingWithout Contamination, JPT5, no. 9 (September 2006):32, 34.

19. PVT-quality samples are those that have sufficiently lowcontamination, such that PVT properties measured in thelaboratory correspond to those of an uncontaminatedsample. The maximum allowable contamination variesby company and laboratory. A general rule is 7%contamination for this basin.

20. Alboudwarej H, Felix J, Taylor S, Badry R, Bremner C,Brough B, Skeates C, Baker A, Palmer D, Pattison K,Beshry M, Krawchuk P, Brown G, Calvo R,Caas Triana JA, Hathcock R, Koerner K, Hughes T,

Kundu D, Lpez de Crdenas J and West C:Highlighting Heavy Oil, Oilfield Review18, no. 2(Summer 2006): 3453.

21. Kumar S and Kundu D: Fluid Sampling in Oil BasedMud Environment: Quicksilver Probe Aids AcquiringContamination Free Samples in a ChallengingEnvironment, to be presented at Petrotech 2007, the7th International Oil & Gas Exhibition, New Delhi, India,January 1519, 2007.

> Pressures and sampling results from a high-permeability zone in a complex Middle East field.

Formation pressures appear in Track 1, with gas identified as orange circles and oil as green circles.Gamma ray and caliper appear in the depth track. Track 3 contains resistivity curves and drawdownmobility (circles). Track 4 plots density and neutron porosity. Focused sampling stations with theQuicksilver Probe module are indicated with small probe insets. At the top sampling station, gas wassampled from a high-permeability zone. Downhole fluid analysis at this station (top right) showsvolume fraction and GOR values from the CFA Composition Fluid Analyzer. In the volume-fraction plot,yellow, red and green indicate C1, C2to C5, and C6+, respectively. GOR values (magenta) point tosampling-line cleanup. At the third station, optical densities from the LFA Live Fluid Analyzer in thesample line (dark blue) are greater than those in the guard line (light blue), showing cleaner fluid inthe sample line. Analysis of CFA results at the same station displays similar results. At the fourthstation, in a high-permeability oil zone, LFA measurements of GOR detect cleanup in the sampleflowline (bottom right).

10,0005,000

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

Sample line

Guard line

Formation Pressure, psi

Depth, ft

Gamma Ray

0 200gAPI

Caliper4 12in.

Drawdown Mobility

0.2 20,000 0.45 -0.15vol/vol

Neutron Porosity

1.95 2.95g/cm3

Density

mD/cP

100

50

0

30,000

20,000

10,0000

5,000 10,000

100

50

040,000

20,000

05,000 10,

750

500

250

0

1,000 2,000

0.2 20,000ohm.m

Resistivity

X,X90

X,X00

X,X10

X,X20

X,X30

X,X40

X,X50

X,X60

X,X70

X,X80

X,X90

X,X00

X,X10

X,X20

X,X30

X,X40


13/16

required for this zone in other wells (above).

Laboratory analysis determined that contami-

nation in the oil sample acquired by the

Quicksilver Probe tool was too small to measure.

In a second Middle East example, an evalu-

ation well penetrated six reservoirs, including a

discovery. The objectives were to obtain pressure

profiles, identify fluids downhole and acquire

clean fluid samples. In addition, the operator

wanted to establish flow from low-porosity zones

that previously had not been directly tested for

their potential producibility. The operatorselected the Quicksilver Probe device because its

large probe area was better equipped than

conventional large-diameter probes to establish

flow and obtain samples from the low-porosity,

low-permeability formations.

The well was drilled with OBM, and caliper

data showed good hole condition. Fluid sampling

points were selected using free-fluid porosity

readings from the nuclear magnetic resonance

log. On the first pressure and sampling run, the

MDT tool, deployed on wireline, acquired

pressure profiles using the large-diameter probe.

On the second descent, the Quicksilver Probemodule and sampling units were run on drillpipe,

and sampled at five stations (next page, top).

At the second sampling station, downhole

fluid analysis identified oil in a previously

untapped interval. Fluid mobility was so low in

this tight zone that a pressure measurement

could not be acquired. However, the LFA module

in the Quicksilver Probe tool successfully

monitored formation-fluid cleanup and found

a low GOR for the liquid, leading to additional

oil reserves.

Downhole Fluid Analysis

In most reservoirs, fluid composition varies with

location in the reservoir. Fluids may exhibit

gradations caused by gravity or biodegradation,

or they may be segregated by structural orstratigraphic compartmentalization. One way to

characterize these variations is to collect

samples for surface analysis. Another way is to

analyze fluids downhole, without bringing them

to surface. Downhole fluid analysis (DFA) is

emerging as a powerful technique to charac-

terize fluids downhole. DFA helps determine the

best intervals for sample collection, if necessary.

Analyzing fluid composition while the tool is still

in the hole also allows more detailed fluid

characterization, because interpreters can

modify the fluid-scanning program in real time to

investigate unexpected results.22

The ability of the Quicksilver Probe module to

supply uncontaminated fluids ensures optimal

DFA results, and the faster cleanup time allows

several DFA fluid-scanning stations to be

conducted efficiently without the long station

times associated with conventional sampling. A

combination of DFA and sample collection

helped a Norwegian operator understand

fluids in a well drilled on the Norwegian

Continental Shelf.23

The well was drilled as a final appraisal

before development of an oil field. Because of

environmental restrictions, a production test was

not planned, so it was critical to obtain uncon-

taminated samples and fully characterize fluid

variations within the reservoir. The fluid analysis

would be used in the material selection of subsea

pipeline and surface facilities, process design

and production planning. Because of the high

priority to capture representative hydrocarbon

samples without miscible contamination, the

well was drilled with water-base mud (WBM).

The Quicksilver Probe tool was run in the

1214-in. and 812-in. sections to collect samples of

gas condensate, oil and formation water, and

filled 19 sample chambers from many levels. An

example from one of the more challenging zones,

sampling oil in a relatively tight zone with

mobility of 17 mD/cP, shows how the focusing

technology results in an uncontaminated sample.Fluid cleanup began with commingled flow

first through the guard flowline, then through the

sample flowline. After 1,300 seconds, flow is split

and focusing is achieved by increasing the flow

rate in the guard probe (next page, bottom). The

real-time GOR detected by the CFA module

stabilized at around 2,300 seconds, indicating

that the fluid was clean. However, pumping

continued, and a sample was acquired at 2,800

seconds. The spikes in the GOR curve indicate

the presence of produced fines from the

formation, confirmed later when the sample was

analyzed at surface. Wellsite analysis showedsome sand in the samples, but no detectable

level of WBM filtrate.

In the same well, the focusing method created

optimal conditions for DFA. The spectroscopic

analyzers that indicate when fluid in the flowline

is pure enough to sample also characterized the

fluid composition in terms of three component

groups: methane (C1), ethane to pentane (C2to C5), and hexane and heavier (C6+). This allows

in-situ compositional analysis without collecting

a sample and retrieving it to surface.

16 Oilfield Review

22. Fujisawa et al, reference 2.Mullins OC, Fujisawa G, Elshahawi H and Hashem M:Coarse and Ultra-Fine Scale Compartmentalization byDownhole Fluid Analysis, paper IPTC 10034, presentedat the International Petroleum Technology Conference,Doha, Qatar, November 2123, 2005.

23. OKeefe M, Eriksen KO, Williams S, Stensland D andVasques R: Focused Sampling of Reservoir FluidsAchieves Undetectable Levels of Contamination, paperSPE 101084, presented at the SPE Asia Pacific Oil andGas Conference and Exhibition, Adelaide, Australia,September 1113, 2006.

> Comparison of pumping times to acquire clean oil samples in a Middle East field usingthe Quicksilver Probe module and a traditional probe. In this high-permeabilitysandstone, it took the Quicksilver Probe tool (red) only about 1,600 seconds of pumpingtime to draw low-contamination fluid into the sampling line, while the traditional probe(blue) pumped about three times as long to obtain a low-contamination sample.

GOR

,ft3/bbl

Time, s

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000

600

650

700

750

800

Quicksilver Probe samplingSplit flowlines

Traditional probe sampling


14/16

Winter 2006/2007 17

> Sampling a new discovery in a mature Middle East field. This evaluation well penetrated six reservoirs, including a discovery. In additionto obtaining pressure samples, the operating company performed tests in bypassed low-porosity zones. Formation pressures appear inTrack 1, with oil identified as green circles and water as blue circles. Open circles indicate pressure measurements that do not fall on anygradient. Stars are pressures measured with the Quicksilver Probe tool. Track 2 contains drawdown mobility. Track 3 plots porosity andpore-fluid content with red for oil and blue for water. The second sampling station, at X,300 ft, was a discovery. LFA volume fraction and

GOR results are plotted to the right of the porosity track ( top right). Pump rates and GOR values for the third station are also shown to theright of the porosity track (middle right). A low-contamination sample was also acquired at the fifth station, at Y,100 ftthe first time oil hadflowed from this low-porosity formation. The GOR from this interval (bottom right) was found to be 250 ft3/bbl.

X,300

Y,100

1.0

0.5

0.00

250

500

0 5,000 10,000 15,000

40

30

20

10

0

150

125

100

75

50

25

04,000 6,000 8,000 10,00 0

0 2 ,5 00 5 ,0 00 7 ,5 00 1 0, 00 0 1 2,5 00

1.0

0.5

0.0300

200

100

0

Formation Pressure, psi

Depth

,ft

Drawdown Mobility

0.01 10,000

vol/vol

Porosity

mD/cP Water

Oil

0.5 0

< Fluid cleanup in an oil well offshore Norway. QuicksilverProbe tool operation began with commingled flow throughthe guard flowline, as seen by the increase in guard-flow-line pumpout flow rate (light green, top track), then throughthe sample flowline (dark green, top track). After 1,300 s,flow is split and focusing is achieved by increasing thepumping rate in the guard probe. The GOR (bottom track)responds by stabilizing at around 2,300 s, indicating thatlow-contamination fluid is flowing through the sampleflowline. Sample flowline GOR is red, and guard flowlineGOR is blue. A sample was acquired at 2,800 s, and wasfound to contain no detectable WBM. The spikes in the GORcurve indicate the presence of produced fines from theformation sand. (Adapted from OKeefe et al, reference 23.)

500

500

0

5

10

15

1,000

GOR

,ft3/bbl

Flowrate

,cm

3/s

1,000 1,500 2,000 2,500 3,0000

Elapsed time, s

Guard pump

Sample pump

Guard flowline

Sample flowline


15/16

Two DFA fluid-scanning stations straddledthe gas/oil contact, only 0.5 m [1.6 ft] apart

(above). The lower station at X,X46.0 m indicated

a black oil with apparent density of 0.868 g/cm3

and a low GOR of 133 m3/m3 [740 ft3/bbl]. Half a

meter higher, at X,X45.5 m, the fluid composition

shows a dry gas with apparent density of

0.126 g/cm3 and C1 content in excess of 91 wt%.

The DFA measurements defined the gas/oil

contact within 0.5 m, which was a higher

accuracy than could be achieved using pretest

pressure gradients in this well. The focusing

capability of the Quicksilver Probe tool ensured

that the fluids being analyzed were repre-sentative of reservoir fluids, adding confidence to

the DFA results. Similar measurements at 15

additional DFA stations helped quantify reservoir-

fluid composition and delineate fluid contacts.

Collecting Formation Water Free

of WBM Contamination

In another example from offshore Norway,

focused sampling helped acquire formation-

water samples in an exploration well drilled with

WBM. In this well, water characterization was a

key factor in reservoir description and economic

evaluation. The operator, taking special care tostudy water composition at different times in the

life of the well, collected water samples using the

Quicksilver Probe tool, then also with a dual-

packer probe in casing, and finally with a

drillstem test.24

To facilitate quantification of WBM filtratecontamination, tritium, a naturally occurring

isotope of hydrogen, was added to the WBM as a

tracer. Formation waters do not contain tritium

in measurable amounts, so tritium levels

detected by laboratory testing could be easily

converted to contamination levels.

The first sample was taken with the

Quicksilver Probe focused-flow tool. Flow was

split after 18,700 seconds, and the sample was

collected after 24,960 seconds of pumping.

Laboratory analysis of tritium content showed

the sample to have 0% contamination.

The well was then cased with a 7-in. liner andperforated over the zone of interest. A wireline

formation tester was run inside the liner, along

with inflatable dual packers to isolate the flow

interval. The increased flow area provided by

the packers would minimize the drawdown

required to extract samples and so reduce the

risk of tool sticking.

After a long cleanup time24 hoursduring

which 1,700 liters [450 galUS] of fluid were

pumped from the formation into the borehole, the

formation tester collected two samples. Laboratory

analysis indicated that the samples contained

elevated concentrations of tritium, potassium,calcium and bromide, indicative of contamination

by completion brine and mud filtrate.

The operating company then performed a

DST to test a gas zone above the water zone.

Water flowing with the gas was collected for

analysis, but was found to be heavily contaminated

with completion brine and also contained 46%

hydrate inhibitor.

The Quicksilver Probe samples proved to bethe purest water samples ever collected from the

field, surpassing the quality obtainable from

conventional-probe sampling, cased-hole sampling

or a DST. Analysis of the samples revealed

unexpected compositional characteristics that

were difficult to believe at first, but further

analysis of core and logs corroborated the new

water-composition results.25

In another water-sampling example from

offshore Norway, both focused and conventional

methods applied to the same formation helped

compare cleanup performance. This exploration

well was drilled with water-base potassiumchloride [KCl] drilling fluid, adding difficulty to

the water-sampling program. Because the

formation water and the WBM had similar optical

properties, real-time qualification of contami-

nation relied not on spectroscopic measurements

but on resistivity differences. For quantitative

determination of contamination levels, the

concentration of potassium in the sample,

corrected by subtracting the level assumed present

in the formation water, was divided by the known

concentration in the WBM filtrate at each depth.

In the first sampling sequence, samples were

collected at three times during focused flow, at1,050 seconds, 7,050 seconds and 7,800 seconds,

and showed 8.35%, 0.02% and 0% contamination,

respectively. Temporarily switching off the

guard pump shows the corresponding effect

on contamination (next page, top). An addi-

tional sample collected at 1,550 seconds, after

the guard pump had been stopped, yielded

33.4% contamination.

18 Oilfield Review

24. OKeefe et al, reference 23.

25. OKeefe et al, reference 23.

> Downhole fluid analysis to identify the gas/oil contact between two fluid-scanning stations separated by 0.5 m. Measurements with the CFA modulefound the pure fluid at X,X46.0 m (left) to be a black oil. The composition track (top) indicates 91 wt% C6+ (green) and 8.9 wt% C1 (yellow), with a GOR of133 m3/m3. At the station 0.5 m higher (right), the compositional analysis yields C1 content (yellow) of 91 wt%, and C6+ (green) less than 5 wt%, indicatinga dry gas with a GOR of 56,602 m3/m3. (Adapted from OKeefe et al, reference 23.)

Elapsed time, s Elapsed time, s

1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800 700

0

0.25

0.50

0.75

2,500

5,000

0

50

100

GOR

,m

3/m3

We

ight%

Water

fract

ion

0

0.25

0.50

0.75

2,500,000

5,000,000

0

50

100

GOR

,m

3/m3

We

ight%

Water

fract

ion

800 900 1,000 1,100 1,200 1,300 1,400 1,500 1,600

Data-qualityflag

Data-qualityflag

Depth = X,X46.0 m Depth = X,X45.5 m

C6+ weight%C2 to C5weight%C1weight%

C6+C2 to C5C1 GOR

8.9 weight% 0.1 weight% 90.9 weight% 133 m3/m3

C6+ weight%C2 to C5weight%C1weight%

C6+C2 to C5C1 GOR

91.0 weight% 2.7 weight% 4.6 weight% 56,602 m3/m3


16/16

For the next run, the field engineer shifted

the toolstring 3.5 m [11.5 ft] higher in the same

formation and used a conventional single-probe

tool with a large-diameter packer to sample

formation fluid without focusing (above).

Sampling at this station was designed to allow

direct comparison between the performance of

the focused probe and the conventional probe.

Three sample bottles were filled at this station

after the same cleanup times as the three

samples in the focused-sampling sequence. The

conventionally acquired samples showed con-

tamination levels of 26.2%, 8.6% and 8.2%. Not

only were the focused samples cleaner at every

time comparison, but the focused sample

acquired at 1,050 seconds (17.5 minutes) wa

cleaner than the conventional sample afte

7,050 seconds (2 hours).

Focusing on the Future

The focused-sampling capability of the Quicksilve

Probe tool provides higher purity fluid samples in

much less time than traditional sampling tools

Benefits include higher quality fluid-property

data, access to accurate fluid information earlier

in the reservoir-characterization process, reduced

risk of tool sticking, enhanced capabilities fo

downhole fluid analysis and all the savings

associated with getting the fluid characterization

right the first time.

For some E&P operators, especially those

involved in deepwater activities, the technology

represents the best existing substitute for

prohibitively expensive or environmentally

unfeasible DSTs. The tool can be run without theextensive upfront planning required for DSTs

Other operators have used high-quality

Quicksilver Probe results to optimize DST plans

In either case, the focused-sampling approach

increases efficiency, quality and safety in these

demanding environments.

In several cases, Quicksilver Probe sampling

has yielded surprising results. The technology is

encouraging some operators to review curren

plans and resample zones where other technologies

have given unsatisfactory answers. Operating

companies that have had to drill with WBM for the

purpose of obtaining clean oil samples can nowconfidently drill with OBM, safe in the knowledge

that pure samples can be obtained downhole with

no miscible contamination.

As a result of the high purity of new, incoming

samples, some laboratories have had to create a

new classification for such low contamination

called too small to measure, or TSTM. Now tha

such pure samples are available for laboratory

analysis, researchers and experimentalists may

be able to perform additional analyses and

devise new measurements to better understand

fluid behavior.

An important consequence of the ability toobtain zero-contamination samples downhole i

the improvement in accuracy of real-time

downhole measurements. This will encourage

companies to perform downhole fluid analysis for

a more complete mapping of reservoir fluids than

is done today, and will also promote the addition

of new DFA measurements. LS

> Focused sampling of formation water in a WBM-drilled well offshoreNorway. Because the formation water and the WBM had similar opticalproperties, contamination was determined by changes in resistivity (blue),which leveled with time. This portion of the sampling log highlights theincrease in fluid resistivity when the guard-line pump (black) is temporarilyswitched off, operating only the sample-line pump (green). Sample-flowlinepressure is shown in red. (Adapted from OKeefe et al, reference 23.)

X12

Pressure

,bar

0.030

Resist

ivity,o

hm

.m

X08

X10

X14

X16

X06

X04

X02

X00400 600 800 1,000 1,200 1,400 1,600 1,800 2,000

0.029

0.028

0.031

0.032

Time, s

Quartz-gaugepressure

Resistivity

Sample-pumpmotor speed

Guard-pumpmotor speed

> Conventional sampling of formation water in a WBM-drilled well offshoreNorway, for comparison with the results of the previous figure ( above).The resistivity sensor was coated with mud initially, but began to respond(blue) partway through the sampling program. Resistivity never leveled off,indicating that water samples were still contaminated. Samples acquiredat this station after the same cleanup times as the three samples in thefocused sampling sequence showed contamination levels of 26.2%, 8.6%and 8.2%. (Adapted from OKeefe et al, reference 23.)

Pressure

,bar

X10

X15

X20

X25

X30

X35

X40

X45

X50

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

0.060

Resist

ivity,o

hm

.m

0.055

0.050

0.045

0.040

Time, s

Sample-pump motor speed

Downhole Sampling

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