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Spring 2013 3333

Engineers seeking to characterize reservoirs and

design completions for maximum production effi-

ciency depend heavily on analysis of downhole

reservoir fluid samples and transient pressure

testing. But identifying mobile fluids and defining

hydrocarbon columns can be difficult in complex

formations. Reservoir engineers and petrophysi-

cists use a variety of data to make accurate

reserves estimates and create representative res-ervoir models. These include fluid composition,

pore pressure measurements, reservoir tempera-

ture, reservoir response to pressure changes and

integration of seismic data.

In the past, most formation fluid samples

were captured after they reached the surface

during drillstem tests and production well tests

and were then separated into gas, oil and water

components. These samples were transported to

offsite laboratories for analysis. Well tests con-

tinue to provide engineers with useful data

about reservoir fluids, reservoir size and produc-

tion potential. But characterizing fluids from

samples captured at the surface can be prob-

lematic. Recombination of the separated fluids

at the surface requires great care: It is often

difficult for technicians to avoid contaminatingthe samples or inducing pressure losses during

capture and transportation, particularly when

working at remote locations; re-creating in situ

conditions in the laboratory is difficult but nec-

essary for accurate analysis.

In the 1950s, the industry began addressing

these and other sampling difficulties by introduc-

ing wireline formation testers (WFTs) that were

lowered on wireline logging cable to the zone o

interest. One recent version of these tools uses

dual straddle packers inflated above and below

the sample point, or station, to isolate the forma

tion from wellbore fluids and to expose more

of the formation for sampling (above left)

Formation fluids are then flowed or pumped into

the tool for capture and retrieval to the surface.

Probe-type WFTs use hydraulically operated

arms to force a packer assembly against the

borehole wall (above). The probe, located in the

center of the packer, extends into the forma

tion, and then reservoir fluids flow or are

pumped into the tool. The fluids are analyzed

downhole, and samples may be captured while

pressure is measured using downhole gaugesFluids are analyzed for purity before being

directed to the sample chambers. This allows

contaminated fluids to be removed before wire

line engineers take formation samples. Sample

bottles maintain the fluids at formation pres

sure to avoid phase changes while the samples

are being retrieved to the surface for transport

to a laboratory for analysis.1

>

Dual straddle packer wireline formation tester (WFT). Some WFTs usehydraulic inflatable packers to seal the formation from contamination byborehole fluids during sampling and transient testing.

Borehole fluid

Fluid intakeopening for WFT

Inflatable packer

Inflatable packer

Borehole fluid

> Probe-type WFT. Once a probe-type tool is on

depth, the tool extends pistons from one side of the WFT against the wellbore wall, while a packeassembly is forced firmly against the formation tobe tested. A probe in the center of the packerassembly then extends into the formation; thereservoir fluids flow through the probe into the tool’s flowline and sample chambers for retrieval to the surface. The packer seal, which surrounds the probe, prevents wellbore fluids from mixingwith reservoir fluids.

Packer assembly

Probe

Pistons



34 Oilfield Review

C o n t a m i n a t i o n l e v e l

Time

Acceptable sample

Sample intake

Seal Seal

Contaminated

intake

Guard

intake

Flow tube tosample chambers

Flow tube towellbore

WFTs often delivered fluid samples that were

more representative of reservoir fluids than those

captured on the surface. However, the probes used

in early tools were not applicable in certain forma-

tions where establishing a seal was difficult. In addi-

tion, testing formations in which fluids move slowly

to the tool prolonged the time the tool was on sta-

tion and often resulted in samples that were con-

taminated with excessive mud filtrate. Furthermore,

highly viscous fluids can typically be mobilizedthrough the formation and into the wellbore only by

creating a relatively high differential pressure

between the wellbore and the formation. This draw-

down, or differential pressure, may exceed the rat-

ings of the WFT packer or may cause the borehole

wall in unconsolidated formations to fail, leading to

loss of the seal around the packer assembly.2 A high

pressure differential may also cause the pressure at

the tool to drop below the bubblepoint pressure,

inducing free gas and composition changes in the

oil, which jeopardizes sample integrity.

In certain well conditions, it may be difficult

to capture representative samples using standard

single-probe WFTs because the sealing packer

isolates the formation or the probe assembly only

from drilling or completion fluids in the borehole.

Fluids that have invaded permeable zones may

also contaminate the sample. To acquire a rela-

tively pure sample of reservoir fluids, engineers

use a pumpout module—a miniature pump

included in the WFT toolstring—to flow or pump

fluids from the formation through the tool and

out to the wellbore until contaminants have been

pumped away. The nature of the incoming fluids

is analyzed downhole by a variety of sensors. Flow

is then directed to sample bottles that capture

and store fluids for transport to surface laborato-

ries for analyses.

Under any condition, obtaining a representa-

tive reservoir fluid sample can be a challengebecause it can be difficult for engineers to know

when the flow stream is sufficiently purged of

contaminants. Engineers must rely on informa-

tion about the reservoir and nature and amount

of contaminant invasion to calculate the time it

will take for the formation to clean up at a given

flow rate. This calculation is further complicated

because the flow from the reservoir streams in a

conical volume toward the probe and draws con-

taminants from the near-wellbore invasion zone

as well as from some vertical distance along the

wellbore. The outer edge of this flow stream may

contain significant nonreservoir fluids, which

may then require extended periods of time to be

pumped away. Often, because engineers may

underestimate the amount of time this process

can take, they capture nonrepresentative sam-

ples, or conversely, if engineers overestimate the

time, they spend unnecessarily long and costly

periods of time at the sampling station.

Innovations in WFT designs have done much

to overcome these limitations. For instance, to

shorten cleanup and ensure a representative

sample, Schlumberger engineers developed the

Quicksilver Probe focused extraction of pure res-

ervoir fluid tester, which uses two concentric

sampling areas through which pumped fluids

enter the tool. The outer ring is a conduit for the

more contaminated outer segment of the flow

stream, which is discarded to the wellbore. The

inner probe draws fluids from the more represen-

tative inner section of the conical flow, which

may then be diverted into the WFT sample bot-

tles (below).3

Another innovation, downhole fluid analysis

(DFA), uses optical spectroscopy to identify thecomposition of reservoir fluid as it flows through

the WFT. This technology allows engineers to

determine contaminant levels and begin sam-

pling only after these levels within the flow

stream have reached an acceptably low value.

When DFA is deployed at selected intervals

within a well and in multiple wells, engineers

gain previously unavailable data with which to

perform reservoir architecture analysis.4

In addition to ensuring the purity of samples,

these innovations shorten time on station, which

may aggregate to significant savings in operating

expenses. However, hurdles remain. This article

discusses obstacles to capturing fluid samples in

certain troublesome reservoirs and a new WFT

probe that helps overcome these obstacles. Case

histories from the Middle East, Mexico and

Norway illustrate how the new tool facilitates

fluid sampling in challenging environments.

The Continuing Challenges

In most formation types, enhancements to WFT

technology have greatly increased an operator’s

ability to capture representative fluid samples suit-

able for analysis while obtaining highly accurate

downhole pressures. But operational constraints,

unconsolidated sands, heavy oils and low-permea-

bility rock still impact sampling success.

Traditional dual straddle packers offer one

solution for these conditions. However, this solu-

tion comes with operational concerns. In large

holes, the packers require extended inflation

times, and their relative positioning above and

below the zone being tested creates a large sump

volume. The effect of this storage volume can sig-

nificantly extend cleanup times and create prob-

lems for transient testing measurements in

low-permeability reservoirs.5

In the testing of low-mobility formations, draw-

down pressures during pumpout may become

quite high. The resulting differential pressures can

exceed existing straddle packer ratings of about

31 MPa [4,500 psi]. High differential pressures

may also result from flowing high-viscosity fluid

through unconsolidated sands, causing seal failure

or even borehole wall collapse.

> Formation fluid sampling with the Quicksilver Probe focused sampling tool. The probe has two intakeports, the guard intake surrounding the sample intake (bottom left ). Packers surround and separate these probes and seal against the borehole wall (right ). Formation fluid is blue-gray and filtrate is lightbrown. When pumping begins, fluid flowing through the sample intake is highly contaminated ( top left) ,but contamination levels quickly reach an acceptable value.



Spring 2013 35

Crumbling formations may also foil sampling

operations when sand from the formation plugs

the probe and flowlines. In addition, drilling

through rock with low mechanical strength typi-

cally results in a highly rugose wellbore wall with

few sections of in-gauge hole against which to

obtain a good packer seal.

To address these issues, engineers have

increased probe size 10-fold over the years and

devised probe shapes to better accommodate various formation types. Probes that create

larger flow areas have increased success rates

in tight formations and friable sands, and dual

packer technology has increased the ratings for

differential pressure to 40 MPa [5,800 psi]. DFA

measurements also help ensure sample purity

and enable a different set of complex fluid anal-

yses than is poss ible on samples brought to the

surface and transported to laboratories. The

next step in the evolution of WFTs was recently

introduced by engineers at Schlumberger with

the development of a probe that provides a sig-

nificantly larger flow area between the forma-

tion and the tool while simultaneously providing

a better sealing element.

A Radial Solution

To address the limitations of differential pressure

and issues of related seal and packer failures,

Schlumberger engineers developed the Saturn

3D radial probe. This tool uses four elongated

ports spaced evenly around the circumference of

the module rather than a single probe or dual

packers. The ports are individually isolated from

the wellbore by a single inflatable packer that

creates a large sealing surface against the forma-

tion (right).

The packer used in the Saturn probe seals

more reliably against a rugose borehole than sin-

gle-probe WFT packers do and inflates and deflates

more quickly than the dual straddle packers while

completely eliminating sump volume. The four

openings are embedded in the packer, and each is

significantly larger than those on conventional

probes, which further hastens cleanup.

Cleanup time—a primary component of for-

mation test times—is the period required to

flow the well until contamination of the reservoir fluid flow stream has been eliminated or

reduced to an acceptable level. One key to

reducing prolonged test times is to shorten

cleanup through higher flow rates. To test

whether the Saturn probe design accomplishes

this goal, reservoir engineers constructed a

numerical model comparing cleanup time using

the Saturn probe to those with a traditional

2. Drawdown is a differential pressure condition thatinduces fluids to flow from a reservoir formation into awellbore. It occurs when the wellbore pressure is less than the formation pressure and may occur naturally orbe created by pumping or producing from the well.

3. For more on the Quicksilver Probe tool: Akkurt R,Bowcock M, Davies J, Del Campo C, Hill B, Joshi S,Kundu D, Kumar S, O’Keefe M, Samir M, Tarvin J,Weinheber P, Williams S and Zeybek M: “Focusingon Downhole Fluid Sampling and Analysis,”Oilfield Review 18, no. 4 (Winter 2006/2007): 4–19.

> Saturn probe. The Saturn probe (top ) captures reservoir fluid samples through four large portsspaced evenly on the tool’s circumference. The ports are pressed against the borehole when thepacker that contains them is inflated, which creates a seal separating reservoir fluids from wellborefluids. The tool geometry provides a radial flow pattern (middle, right ) for reservoir fluids (green) andfaster removal of contaminated fluids (blue). This differs from the flow pattern of a typical WFT (middleleft ), which has a single opening on one side of the tool. The Saturn probe also has a flow area that ismany times larger than that of traditional probes (bottom ).

Fluid in takepor ts

Infla tablepacker

79.44Surface flow

area, in.2

6.03Surface flow

area, in.2

The Saturn 3D radial probe, which uses four ports, increases theprobe surface area to more than 500 times that of the standard probe.

2.01Surface flow

area, in.2

1.01Surface flow

area, in.2

0.85Surface flow

area, in.2

0.15Surface flow

area, in.2

Saturn 3DRadial Probe

EllipticalProbe

Extra LargeDiameter Probe

Quicksilver ProbeProbe

Large DiameterProbe

StandardProbe

4. For more on downhole fluid analysis: Creek J, Cribbs M,Dong C, Mullins OC, Elshahawi H, Hegeman P, O’Keefe MPeters K and Zuo JY: “Downhole Fluids Laboratory,”Oilfield Review 21, no. 4 (Winter 2009/2010): 38–54.

5. Wellbore fluid expansion and compression effects distort the reservoir response to pressure changes used inpressure transient analysis. A critical element ofpressure transient analysis is distinguishing between the wellbore storage effects and the true reservoirpressure response.



36 Oilfield Review

extra large diameter (XLD) probe. The team

used ECLIPSE reservoir simulation software on

three probe configurations to test the proposi-

tion. A fine grid was used to model the XLD and

Saturn probes. For miscible contamination,

investigators simulated a single-phase fluid sys-

tem and represented the drilling fluid filtrate

contamination using an embedded tracer. In

addition, investigators conducted immisciblemodeling for oil-wet and water-wet systems.

During the simulated tests, engineers consid-

ered parameters such as permeability, anisotropy,

viscosity contrast between filtrate and oil, disper-

sion of the invasion front and extent of invasion.

In a miscible contamination cleanup scenario,

engineers found that although the breakthrough

of formation oil is faster for the XLD probe,

cleaner samples can be collected with the Saturn

3D radial module with less total volume pumped.

In a simulation of immiscible contamination

cleanup, mud filtrate viscosities of 1.0 cP

[1.0 mPa.s] and 0.6 cP [0.6 mPa.s] were used. In

scenarios using typical water- and oil-wet relative

permeability, cleanup times to reach 5% contami-

nation were similar to those for miscible contam-

ination (above).6

Because mobilizing heavy fluids often gener-ates drawdown pressures high enough to cause

weak formations to collapse, the combination of

high-viscosity fluids in poorly consolidated sands

constitutes one of the most formidable wireline

formation testing challenges.

The behavior of fluid flow from the reservoir

to the sampling tool is governed by Darcy’s law,

in which flow is directly proportional to perme-

ability, drawdown pressure and cross-sectional

surface area and inversely proportional to fluid

viscosity and the length over which the draw-

down is applied. By introducing a flow area

about 40 times larger than that of traditional

XLD probes, the Saturn probe reduces the nec-

essary drawdown pressure to mobilize heavy

fluids or fluids in low-permeability formations

(next page, top).

In the past, traditional WFT options restricted

operators to a choice between the higher draw-down and reduced flow rate of a traditional probe

and the larger flow rate of a straddle packer. The

disadvantage of lower flow rates is longer cleanup

times. On the other hand, while dual packers

allow higher flow rates than the flow rates of tra-

ditional probes, they create large storage vol-

umes and may lose seal because they cannot

provide necessary borehole wall support in

unconsolidated formations. The Saturn probe

design provides the benefit of both a probe and a

dual packer: a large flow area to reduce time to

cleanup and a packer-probe configuration that

provides mechanical support of borehole walls to

create a more reliable seal.

The Saturn 3D radial probe innovations allow

operators to capture samples, perform DFA and

identify transient flow regimes in situations where

they previously could not. These include low-per-

meability formations, heavy oils, unconsolidated

formations, single-phase fluids close to the bubble-

point, ultratight formations and others.7

Putting Theory to the Test

An operator deployed the Saturn tool to distin-

guish between oil and water zones in formations

that had been difficult to test using traditional

tools. Among the problems was a history of forma-

tion tests in which mud losses had restricted

sampling time to four hours per station. Because

these were also low-mobility formations, this

operational constraint made it difficult to cap-

ture samples using traditional probes.

Engineers viewed this operation as an oppor-

tunity to compare the Saturn tool with traditional

sampling methods. They designed a WFT tool-

string that comprised an XLD probe, a Saturn

probe, a compositional DFA module and several

sample bottles. Engineers took multiple pressuremeasurements as the tool was run into the hole,

6. Al-Otaibi SH, Bradford CM, Zeybek M, Corre P-Y,Slapal M, Ayan C and Kristensen M: “Oil-WaterDelineation with a New Formation Tester Module,”paper SPE 159641, presented at the SPE Annual TechnicalConference and Exhibition, San Antonio, Texas, USA,October 8–10, 2012.

7. Mobility is the ratio of formation permeability to fluidviscosity. Therefore, lower formation permeability orhigher fluid viscosity decreases mobility.

> Parameters of a cleanup test simulation. Engineers performed a modelcomparison of the cleanup efficiency of the Saturn probe, dual straddlepacker and XLD probes using a reservoir model based on specific wellbore,formation, fluid and simulation parameters (top ). Model output (bottom )confirmed that the greater flow area of the Saturn probe significantlydecreased cleanup times for various vertical and horizontal permeabilities forboth water-wet and oil-wet sands. The simulations take into account thestorage effects of the dual packer sump. In these simulations, a sump volume

of 17.0 L [4.5 galUS] is assumed, and oil- and water-base mud filtrates areassumed to be segregated instantaneously within the sump. The intervalheight between packers is 1.02 m [40 in.].

Porosity

Horizontal permeability

Vertical permeability

Wellbore diameter

Formation thickness

Tool distance from boundary

Formation pressure

Maximum drawdown during cleanup

Maximum pumpout rate

Depth of filtrate invasion

20%

10 mD

2 mD

21.6 cm [8.5 in.]

50 m [164 ft]

25 m [82 ft]

21 MPa [3,000 psi]

4 MPa [600 psi]

25 cm3 /s [0.4 galUS/min]

10 cm [4 in.]

Common Parameters Value

Oil viscosity

Oil-base mud filtrate viscosity

1 cP

1 cP

Oil viscosity

Water-base mud filtrate viscosity

1 cP

0.6 cP

Relative permeability

Residual oil saturation

Irreducible water saturation

Water relative permeability

Oil relative permeability

Water and oil core exponents

Connate water saturation

Water-wet

0.10

0.20

0.20

1.00

3.0 and 1.5

0.12

Oil-wet

0.30

0.15

0.80

0.60

1.5 and 3.0

0.12

Model Output

Model Output

Value

Saturn 3D radial probe

XLD probe

Saturn speedup over XLD probe

0.71 h

9.10 h

12.8

0.42 h

7.17 h

17.0

0.99 h

14.61 h

14.8

MiscibleCleanup

Immiscible Cleanup, Water-Wet

ImmiscibleCleanup, Oil-Wet

Miscible Cleanup Parameters Value



Spring 2013 37

and seven samples were captured as the tool-

string was retrieved from the well.

At the first station, samples were captured

using the XLD probe after DFA measurements

had identified 60% to 70% oil in the flow stream.

The operator chose Station 2 in an effort to deter-

mine the depth of lowest mobile oil. Engineers

attempted to capture a sample at Station 2 using

the XLD probe, but with a 13.8-MPa [2,000-psi]

drawdown, a flow rate of only 5.2 L/h [1.4 galUS/h]could be achieved. After 1.5 hours of pumping,

flow was switched to the Saturn probe, and

although the flow rate was increased to 7.8 L/h

[2.1 galUS/h], the accompanying drawdown was

only 4.7 MPa [680 psi]. Under these conditions,

flow stability was achieved and engineers were

able to identify the oil/water delineation within

the previously imposed four-hour time limit.

While sampling at Station 2 with the XLD probe,

engineers observed no oil flowing in the first 34 L

[9.0 galUS] pumped during cleanup (below). Even

accounting for the XLD probe contribution, engi-

neers concluded that oil arrived at the tool faster

> Three-dimensional contamination distribution. Models of cleanup using the Saturn probe and an XLDprobe are shown at four points in time. The same drawdown is applied to both the XLD and the Saturn

probes, but because of its larger flow area and multiple, circumferentially spaced drains, the Saturnprobe can operate at higher pump rates and consequently achieve cleanup 12 to 18 times faster than the XLD probe. (Adapted from Al-Otaibi et al, reference 6.)

S a t u r n

P r o b e

Time 1 Time 2 Time 3 Time 4

X L D P

r o b e

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

> Finding oil. Logs of formation pressure (Track 1), mobility (Track 2), density-neutron-sonic (Track 3) and resistivity (Track 4) in this Middle East well would leadanalysts to assume the target formation to be devoid of oil. However, DFA (Track 5) during pumpout indicated the presence of oil in the carbonate formation.

0.367 psi/ft (oil)

Formation Pressure

PretestMobilitymD/cP

Fluid Type

Lithology

MDTStation

psi 930 1,000530

Photoelectric Factor

0.01

46

48

49

50

51

52

70%water

30%oil

40%water

water

Station 2

Station 1

Station 3

60%oil

0.477 psi/ft (water)

± 0.021 psi/ft

Invaded Zone Resistivity

ohm.m

Bulk Density Correctiong/cm3

Formation Density

g/cm3

Thermal Neutron Porosity

%

Delta-TSonic Porosity

%

10-in. Array Inductionohm.m

20-in. Array Induction

ohm.m


ohm.m


ohm.m

Resistivity

Sandstone

Porosity

Dolomite

Limestone



38 Oilfield Review

using the Saturn probe, which they attributed to the

increased flow rate and radial cleanup.

The operator also tested a low-porosity, low-

resistivity zone in the field. The first attempt,

performed with an XLD probe, produced a

13.8-MPa drawdown and flow rate of less than

72 L/h [19.0 galUS/h]. Using the Saturn probe,

engineers were able to reduce drawdown to

7.6 MPa [1,100 psi] with a flow rate of 288 L/h

[76.1 galUS/h]. As a consequence, they were able to

capture sufficient samples to delineate the oil/water

contact (OWC) using the optical density mea-

surements of the DFA module.

The Saturn probe was also used to identify a

small amount of oil in a low-mobility zone in

which pumpout was not possible with the stan-

dard XLD probe. And finally, the operator sought

to use sampling and DFA to determine the OWC

in a heterogeneous carbonate formation with a

resistivity measurement of 0.7 ohm.m. In thisinstance, in which traditional sampling tech-

niques were unsuited to the task, engineers were

able to use DFA measurements in conjunction

with fluid samples captured with the Saturn tool

to determine the thickness of the oil zone.8

Heavy Oil Challenge

Heavy oil is particularly problematic for conven-

tional downhole sampling devices. Production of

this type of resource through proper placement

of injection and production wells can be highly

dependent on accurate fluid characterization.

Because moving high-viscosity oil to the wellbore

and then to the surface is often accomplished

using steam injection and artificial lift, it is criti-

cal for operators to be aware of higher-mobility

zones within the reservoir layers created by rela-

tively high-permeability rock or low-viscosity

fluid. Both situations may create preferential

high-mobility pathways through which the oil and

steam flow and often result in significant

bypassed reserves.

In 2011, the national oil company of Mexico,

Petróleos Mexicanos (PEMEX), reported 60% of the

nation’s oil reserves were heavy or extra heavy oil. 9

As other more easily produced reserves are drained,

these resources have become increasingly impor-

tant to PEMEX and the nation. In the Samaria

heavy-oil field in southern Mexico, PEMEX is tryingto produce fluids with viscosities at downhole condi-

tions as high as 5,000 cP [5,000 mPa.s] from forma-

tions with unconfined compressive strength of from

0.69 to 5.5 MPa [100 to 800 psi].10 Because of chal-

lenges presented by the combination of high-viscos-

ity fluid moving through an unconsolidated

formation, operators have been able to use WFTs to

take pressure measurements in these formations

but have been unable to capture samples. In the

Samaria field, PEMEX engineers have instead perfo-

rated and flowed each zone individually and deployed

sampling bottles on coiled tubing or a drillstring.

Because this approach proved impractical and

costly—often taking days or weeks per zone—the

operator abandoned this sampling method.

As PEMEX engineers began a new develop-

ment cycle in these Tertiary-age sandstones, they

turned to the Saturn probe in 2011 to evaluate

four wells. The primary team objective in the first

well was to test the functionality of the new tool.

In the second and third wells, engineers moved to

full pressure testing with fluid scanning and sam-

pling. In the fourth well, they also planned inter-

val and vertical interference testing.

Multiple stations were tested and sampled in

each of the wells. Because the formations are

unconsolidated, the wellbores are often rugose

and out of round—conditions that may cause a

traditional probe to lose its seal before cleanup is

> Fluid sampling. The Saturn tool was used to acquire fluid samples and measure pressure (red) at thezone of interest. Initial measurements are mud pressure. At about 2,500 s, the tool is set and pumpoutbegins, followed by a buildup beginning at about 10,000 s, which establishes an estimate of reservoirpressure. Cumulative total volume pumped (green) begins to increase when the pump is turned backon at about 18,000 s to begin cleanup. At around 40,000 s, a second pump is engaged, which increasespump rate. The drawdown increases because of higher pump rate and the arrival of high-viscosity oilat the tool. Two spikes in pressure at about 55,000 s are the results of pressure shocks created whensamples are captured followed by stopping the pump. Pressures are also recorded by an observation

probe (black). Pumpout rates (tan and blue) are recorded on the far right axis in cm3 /s for the first andsecond pumps, respectively. (Adapted from Flores de Dios et al, reference 10.)

G a

u g e p r e s s u r e

, p s

i

V o

l u m

e p u m p e

d ,

1 , 0

0 0 c m

3

2,000

1,800

1,600

1,400

1,200

1,000

800

600

400

200

0

10

0

10

40

20

30

20

3040

50

60

70

80

90

100

110

P u m p o u t r a t e

, c m

3 / s

Elapsed time, s

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000

Saturn 3D radial probe pressure

Rate pump 2

Rate pump 1

Volume pumped

Quartz pressure gauge (observation) pressure

8. Al-Otaibi et al, reference 6.

9. Petróleos Mexicanos (PEMEX) Exploración y Producción:“2011: Las reservas de hidrocarburos de México,”Mexico City: PEMEX (January 1, 2011): 22 (in Spanish).

10. Flores de Dios T, Aguilar MG, Perez Herrera R, Garcia G,Peyret E, Ramirez E, Arias A, Corre P-Y, Slapal M andAyan C: “New Wireline Formation Tester DevelopmentMakes Sampling and Pressure Testing Possible inExtra-Heavy Oils in Mexico,” paper SPE 159868,presented at the SPE Annual Technical Conference andExhibition, San Antonio, Texas, October 8–10, 2012.

11. Flores de Dios et al, reference 10.



Spring 2013 39

accomplished and samples captured. In the first

well, tests were run with an XLD probe and a

Saturn probe to test the sealing efficiency of the

new system and to adjust variables such as set-

ting and unsetting time, minimum inflation pres-

sure for a seal and optimal pretest volume to

account for storage effects.

The Saturn probe achieved 100% sealing in

each of the seven stations tested using packer

inflation pressures as low as 0.2 MPa [30 psi]. As

a consequence, engineers were able to obtain

full pressure surveys in both oil- and water-base

mud environments that indicated only minor

storage effects on the pressure responses.

PEMEX engineers used the pressure surveys

and mobilities determined from pretests to

design completions that will evenly distribute

injected steam in designated intervals, which

will increase sweep efficiency.

As the testing for the Saturn tool continued,engineers captured minimally contaminated

fluid samples from three wells using a toolstring

that included an XLD probe and Saturn probes,

fluid analyzers and sample bottles. Because of

the unconsolidated nature of the formations,

PEMEX engineers expected to use low differen-

tial pressures that would require 16 to 20 hours

per station to capture a sample; much of the time

would be used to pump filtrate ahead of reservoir

fluids during cleanup. At the first station, while

limiting differential pressure, engineers saw first

hydrocarbon after 9 hours of pumping.

The pump speed was accelerated, and the dif-

ferential pressure rose to about 200 psi [1.4 MPa];

no sand was seen in the tool. Flow pressure also

decreased, indicating that the seal was holding.

This led the team to abandon the original plan for

low drawdown pressures and instead establish a

300-psi [2.1-MPa] differential minimum for

Station 2 (previous page). The minimally con-

taminated sample collected at this station was

7.5°API gravity oil; subsequent laboratory analy-

sis documented that this sample had a viscosity

of approximately 1,030 cP [1.03 Pa.s] at down-

hole conditions and about 7,800 cP [7.8 Pa.s] at

atmospheric conditions. Engineers will use the

results from laboratory analysis of the samples in

completion and production planning of the field.

In the fourth well, engineers performed interval pressure transient tests using the Saturn probe

combined with an observation probe. These tran-

sient tests consist of complete cleanup of the mud

filtrate followed by variable-rate flow and shut-in

periods, which are used to evaluate formation

deliverability. Data from an observation probe

higher on the toolstring provided engineers with

information about formation permeability and

permeability anisotropy (above). PEMEX engi

neers are applying this information to calibrate

cutoffs in nuclear magnetic resonance log pro

cessing, which they use to fine-tune permeabil

ity predictions.11

Low Mobility and High Confidence

Using resistivity log measurements, petrophysi

cists are able to delineate oil/water contacts in

the majority of formations. However, in some for

mations, operators have difficulty interpreting

the log response where water- and oil-bearing

zones intersect. This uncertainty can affect how

engineers choose to complete the well.

For one Middle East operator trying to deter

mine the extent of an oil zone in a tight carbon

ate formation, logs strongly indicated that the

top of the zone was oil bearing and the bottom

was water bearing. But log results for the

middle zone were ambiguous; the resistivityresponse was similar to that of the water zone

below it. Resolving the question of the fluid

types of the middle zone with DFA measure

ments using traditional downhole sampling

tools was precluded because establishing flow

from the tight carbonate formation would have

created a differential pressure greater than tra

ditional dual packer ratings.

> WFT interference test. The Saturn probe was run beneath a single-probe WFT. Engineers conductedan interval pressure transient test, obtaining vertical permeability (k v ) and horizontal permeability (k h ).Delta P and its derivative were recorded by the shallower observation tool (blue) and by the Saturn tool(green). Models were built using values of 12.2 m, 640 mD, 120 mD and 370 cP for height, k v , k h andviscosity, respectively. The modeled values (solid blue and green lines) reproduce the data closely,

indicating that values for vertical and horizontal permeabilities are correct. (Adapted from Flores deDios et al, reference 10.)

D e

l t a P a n

d d e r i v a t i v e

, p s

i

Time since end of drawdown, s

10

101

101

102

103

102 10310

Modeled delta P , Saturn tool

Modeled derivative,Saturn tool

Modeled delta P ,WFT observation probe

Modeled derivative,WFT observation probe



40 Oilfield Review

Using the Saturn probe, however, engineers were able to collect samples in all three zones,

which confirmed light oil in the top zone and water

in the lowest zone. After 15 hours of pumping at

4,900-psi [34-MPa] differential pressure from the

0.04-mD/cP mobility zone, DFA measurements

indicated the presence of mobile light oil in the

middle zone, which allowed the operator to deter-

mine that the thickness of the oil zone was greater

than initial estimates (above).

Drawdown RestrictionsIn some instances, operators have reason to use

the Saturn 3D radial probe, even though a tradi-

tional one might suffice. After engineers at Eni

SpA saw the results achieved using the new

probe in Ghana, engineers at an affiliated com-

pany, Eni Norge, elected to try the service in the

Goliath field in the Barents Sea. Engineers at

Eni used this application to test sandstones in a

relatively low-mobility environment, update the

> Low-mobility carbonate. Wireline log measurements (top ) were inconclusive or provided conflictinginterpretations in a formation in the Middle East. Porosity (Track 1) and resistivity (Track 2)measurements indicate an oil-bearing zone. However, log data from a middle zone were similar to thoseof the deeper water-bearing zone. Engineers resolved uncertainty in the middle zone by using theSaturn probe to capture a reservoir sample and a DFA module to measure fluid properties. Downholefluid analysis (Track 3) indicated, similar to that in the top zone, the presence of oil in the middle zone.Flow from the tight carbonate formation required a differential pressure of 4,900 psi (bottom ), whichexceeds traditional WFT and packer ratings. (Adapted from Al-Otaibi et al, reference 6.)

Limestone

Lithology

Porosity

Dolomite

P r e s s u r e

, p s

i

F l o w

r a t e

, c m

3 / s

Time, s

0500

0 10,000 20,000 30,000 40,000 50,000 60,000

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

0

5

10

15

20

25

305,500

Pressure

Rate

Photoelectric Factor

Invaded Zone Resistivity

ohm.m

Bulk Density Correction

g/cm3

Formation Density

g/cm3

Thermal Neutron Porosity

%

Sonic Porosity

%


ohm.m


ohm.m


ohm.m


ohm.m

Resistivity

Fluid TypeMDT

Station

Water

4,900-psipressure

differential

Sandstone

Clay

reservoir model and fluid contacts and increase

their understanding of this new technology.

During the testing operations, the formation

pressure survey encountered some supercharged

low-mobility zones at the bottom of an oil col-

umn. This introduced some uncertainty in the

pressure gradient interpretation.12 Finding a

clear delineation of the OWC also proved difficult

because the resistivity log response could be

attributed to either high water saturation or deepinvasion effects. Fluid scanning with the Saturn

probe identified the location of the OWC 5.5 m

[18 ft] deeper than indicated by pressure gradi-

ent and log response.

Furthermore, because of the large flow area

of the Saturn probe, the strength of the lami-

nated and low-permeability rock was confirmed.

In this case, although reservoir mobility was a

moderate 45 mD/cP, the reservoir pressure was

near saturation pressure. Thus, a low drawdown

pressure was essential to prevent a high pressure

differential that might induce two-phase flow

and an unrepresentative gas/oil ratio. Using

the Saturn probe, a drawdown of only 0.5 bar

[0.05 MPa or 7.3 psi] was needed to scan and

clearly identify reservoir oil. A sample was also

acquired using an XLD probe at another station

in the same well in which the reservoir mobility

was 880 mD/cP—more than an order of magni-

tude greater than that of the reservoir sampled

using the Saturn probe. Compared with the flow

rate of the XLD probe, the Saturn probe achieved

twice the flow rate at half the drawdown (next

page). As a result, cleanup time was one-third

of that using the XLD without raising concerns

over the effects of extreme pressure changes on

sample integrity.

Another Step Forward

The industry’s ability to capture fluid samples and

critical pressure data has evolved rapidly since the

1970s. Innovations in these arenas have been

spurred by need to develop more-complex forma-

tions with tighter limits on testing operations.

With increasing frequency, engineers are testing

weaker formations and producing high-viscosity

fluids, which means tests must take less time at

each station with lower drawdown ranges andlower flow rates. Often, these restrictions conspire

to make sampling impossible.

12. Supercharging occurs when mud filtrate invading through the wellbore wall during drilling creates anoverpressure in the formation around the wellbore.Pressure tests with WFTs, performed during the pretest,are affected by this overpressure, which is higher than the true formation pressure.



Spring 2013 41

> Drawdown and flow rate comparison. Engineers at Eni chose the Saturn probe to capture samples from a 45-mD/cP mobility reservoir and a single XLD

probe to capture a sample in a much higher 880-mD/cP mobility reservoir within the same well. While flow rate (top , green line) through the Saturn probe(left ) was nearly twice that of the XLD probe (right ), the drawdown (blue line) was half that of the XLD probe. Fluorescence monitoring during cleanup(middle ) indicated cleanup as fluorescence increased with fluid purity. The reservoir tested using the Saturn probe reached cleanup in 10 minutes ( bottomleft ) compared with the XLD probe, which cleaned up in about 30 minutes ( bottom right ).

195.0

194.5

194.0

193.5

193.0

192.5

192.0

191.5

191.0

190.5

190.0

50

45

40

35

30

25

P r e s s u r e ,

b a r

F l u o r e s c e n c e

Elapsed time, min0

0

0.51.0

1.5

2.0

2.5

3.0

3.5

Elapsed time, minWater Mu d-co ntam in ated fl ui dOil

0 5 10 15 20 25 30 35 40 45 50

5 10 15 20 25 30 35 40 45 50

F l o w

r a t e ,

c m

3 / s

20

15

10

5

0

195.0

194.5

194.0

193.5

193.0

192.5

192.0

191.5

191.0

190.5

190.0

50

45

40

35

30

25

P r e s s u r e ,

b a r

F l u o r e s c e n c e

F l u i d f r a c t i o n ,

%

F l u i d f r a c t i o n ,

%

Elapsed time, min0 10 20 30 40 50 60 70 80 90 100 110 120

F l

t

3 /

20

15

10

5

0

Flow rate

40 cm3

/s

Flow rate22 cm3 /s

Drawdown

DrawdownQuartz gauge pressure,Sample line pressure

45-mD/cP Mobility Reservoir 880-mD/cP Mobility Reservoir

Pumpout totalflow rate

Fluorescence Channel 0

Fluorescence Ratio

Fluorescence Reflection


Quartz gauge pressure,Sample line pressure

Pumpout totalflow rate

0

0.51.0

1.5

2.0

2.5

3.0

3.5


Fluorescence Ratio

Fluorescence Reflection


100

80

60

40

20

0

Elapsed time, min

0 10 20 30 40 50 60 70 80 90 100 110 120

100

80

60

40

20

0

10 min 30 min

The Quicksilver Probe tool design shortens

time on station, and DFA technology provides

engineers with critical and timely knowledge

about reservoir fluids as they are captured. Both

these advances have allowed operators to gather

pressure and fluid sample data more quickly and

with greater confidence in the results.The Saturn probe expands the range of situa-

tions and conditions in which WFTs are applicable;

these include low-permeability or unconsolidated

formations, heavy oil, near-critical fluids and

rugose boreholes. The Saturn probe openings are

configured to create a total surface flow area

1,200% greater than that of the largest conven-

tional single-probe formation testers. This larger

area means flow of viscous fluids is less restricted

and pressure differentials are reduced; viscous

fluid flow and pressure differentials are the pri-

mary constraints to testing in formerly inaccessi-

ble environments.

In addition to allowing operators to take mea-

surements and samples in these formations, in

most cases the Saturn probe works to morequickly dispose of filtrate and contaminated for-

mation fluids, reducing time on station. Constant-

drawdown simulations in low-mobility reservoirs

show the Saturn tool to be orders of magnitude

faster than standard XLD packer probes in com-

pleting cleanup. With no sump, transient flow

regimes can be recognized earlier, extending the

range of applicability of interval pressure tran-

sient tests.

Shorter operating time is not trivial on some

of today’s projects in which operating costs often

exceed $US 1 million per day. The Saturn probe

addresses this issue of high-cost time through

higher flow rates that save operators hours and

even days of operating expense. Similarly, data

from the Saturn probe allow engineers to makecritical completion and production decisions

based on hard facts rather than estimates, and

that can make the difference between success or

failure, profit or loss. —RvF

03 dimensions mdt

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