A revolution in reservoircharacterization

Wireline formation testers have evolved through a series ofinnovations and small refinements. The new Modular Formation

Dynamics Tester (MDT*) tool now offers major innovation - multiplesampling during a single wireline run, and rapid pressuremeasurement using new generation quartz gauges that stabilisequickly to measure formation pressure. Multiple, uncontaminatedfluid samples, fast and accurate pressure surveys, determination ofpermeability anisotropy and even a mini drillstem test on wireline areall within the reach of the engineer today.

In this article Cosan Ayan, Adrian Douglas and Fikri Kuchuk showsome of the initial applications of the MDT tool.

Special Contribution - Anya Radeka for thorough and challenging field testing of the MDT

tool in the Middle East while with the Technique Department in Dubai.

44 Middle East Well Evaluation Review

When wireline formation testers

were introduced, almost 40

years ago, there was one simple

objective - fluid sampling. The first wire-

line testing tool, the Formation Tester,

was introduced in 1955, specifically to col-

lect reservoir fluid samples, but could

only collect one sample per trip in the

well. This tool was replaced first by the

Formation Interval Tester (FIT*) and

then, in 1975, by the Repeat Formation

Tester (RFT*) tool.

The arrival of the RFT tool allowed

operators to devise new applications for

wireline testing. The fluid sampling capa-

bilities of the RFT tool often played a sec-

ondary role to the repeat pressure

measurements which this tool made pos-

sible for the first time.

The most recent step of this evolu-

tionary progression is the development

of the Modular Dynamics Formation

Tester (MDT*) tool. As a replacement for

the RFT tool, the MDT tool offers signifi-

cant improvements in pressure measure-

ment, thanks to its Combinable Quartz

Gauge (CQG*) and improved sampling

capabilities (figure 3.1).

The collection of condensates and

critical fluids at the sandface, one of the

most difficult downhole sampling opera-

tions, can be carried out quickly and effi-

ciently using the new tool with very

small pressure drawdowns.

Recently, the MDT tool was used to

determine lateral hydraulic continuity in

a Middle East sandstone reservoir. The

tool was run in a horizontal well using

the Tough Logging Conditions (TLC*) sys-

tem. Deployed in its basic configuration,

the MDT tool generated a pressure pro-

file (figure 3.2) which indicated a low

porosity interval between x280 ft and

x350 ft, which acted as a flow barrier, and

consequently a significant pressure differ-

ential had developed across this interval.

One of the most important improve-

ments offered by the new tool is the abil-

ity to control a multitude of tool functions

from the surface. The MDT tool’s single

probe module contains a 20 cc pre-test

chamber. However, the size of this cham-

ber can be adjusted from the MAXIS-500*

(wellsite surface instrumentation) acqui-

sition unit.

Electric power module

Sample modules

Hydraulic power module

Hydraulic power module

Probe moduleProbe module

Sample modules

Electric power module

Multi-sample modules

Pump-out module

Optical fluid analysis module

Flow control module

Dual probe module

Dual- packer module

Fig. 3.1: A MODEL OF MODULARITY: The

standard MDT with the single probe module

and multiple sample chambers. The single

probe module offers a variable pre-test

chamber and a new CQG (Combinable Quartz

Gauge) which provides fast and accurate

pressure measurements. The optional modules

provide permeability anisotropy, mini DST

(drillstem test), sampling and fluid

identification capabilities. The tool's modular

design enables engineers to select the modules

required for a particular operation.

This feature allows the engineer to

reduce chamber volume for faster tests

in tight zones where flow rates are very

low. Another type of surface pre-test is to

set the maximum allowable pressure

drop during the test. This prevents gas

liberation around the probe in tight for-

mations.

45Number 16, 1996.

Figure 3.3 shows two pre-tests which

were carried out at the same depth. The

first used a pre-test chamber size of 7 cc

and achieved stabilized build-up pres-

sures in five minutes. The other, which

filled a 20 cc chamber, required 17 min-

utes to reach formation pressure. The

option of variable pre-test chamber size

means faster surveys and helps the engi-

neer to avoid dry/incomplete tests in

low-permeability zones.

Fluid contacts

The depths at which water is overlain

by oil (the oil-water contact) and oil is

overlain by gas (the gas-oil contact) are

very important reservoir parameters.

Once we have an accurate picture of

the reservoir’s internal boundaries we

can estimate actual volume of oil and

gas in place. This is clearly very impor-

tant in the early stages of field develop-

ment, when the emphasis is on

identifying overall reservoir extent. The

well completion methods selected to

minimize gas-water coning will depend

on the locations of the gas-oil and oil-

water contacts.

HY

P(p

sia)

HY

P(p

sia)

RH

OB

(G/C

3)

95 45

2.95

-.15

NP

HI

2000

4000

x250

x300

x350

x400

x450

x500

x550

Fig. 3.2: SIDEWAYS GLANCE: An MDT tool-derived pressure profile and the density-neutron log recorded in a horizontal well in a Middle East sandstone.

The MDT tool was run in this well to verify hydraulic continuity throughout the reservoir. The density-neutron plot shows a relatively low porosity

interval from x280 ft to x350 ft. Unfortunately, it is not apparent from these logs whether or not the zone is a permeability barrier. However, the formation

pressure measured with the MDT tool gives a clear indication of pressure discontinuity along the well trajectory.

100 200 300 400 500

1100

1102

1104

1106

1108

1110

Time (sec)

Pre

ssur

e (p

si)

7 cc pre-test at x120 ft

100 200 300 400 500

1100

1102

1104

1106

1108

1110

Time (sec)

Pre

ssur

e (p

si)

20 cc pre-test at x120 ft

Fig. 3.3: TIME SAVER:

Stabilization times can

be reduced by lowering

the volume withdrawn

during pre-tests. Pre-tests

taken at the same depth

show that while a build-

up preceded by 7 cc

drawdown (a) stabilizes

in five minutes, it takes

17 minutes to reach

formation pressure

when withdrawing 20 cc

during drawdown (b).

(a)

(b)

46 Middle East Well Evaluation Review

Density-Neutron Pressure (psi) Resistivity

TVD

7200

7100

Water

Oil

Gas

GR

compensated, ensuring an excellent

dynamic response. A few minutes can be

saved during each test and, when many

pre-tests are performed, the minutes add

up to hours of rig time.

Sweet success in sour gas

Home Oil and partners recently drilled a

carbonate test well in Alberta, Canada.

The hydrocarbon target was a gas zone

rich in natural gas liquids and highly toxic

hydrogen sulphide (H2S). The reservoir

was highly dolomitized and contained a

lot of vugs. This vuggy character meant

that conventional logging could not iden-

tify fluid gas contacts precisely, with dis-

crepancies between logging runs of

approximately 9 m.

It is vital that the exact contact depths

are known in order to estimate reserves -

a particularly important consideration in

sour gas reservoirs. Reservoirs with a

high H2S content require special ‘scrub-

bing’ facilities which may be too expen-

sive to install on a small field. An

over-estimate of reserves could encour-

age development of an uneconomic

field, while an under-estimate might

result in a missed opportunity.

Fig. 3.4: FLUID FINDER:

Formation pressures

can be used to define

fluid type at any given

depth within the

reservoir and to locate

fluid contacts.

Fig. 3.5: GAUGE THE DIFFERENCE: In this

example the module was equipped with a

conventional quartz gauge and the CQG. This

allowed a direct comparison between the two

pressure datasets during each pre-test. The

conventional gauge (a) had not reached

formation pressure after 150 seconds, while the

CQG (b) was fully stabilized after just 100

seconds.

The excellent resolution and accuracy

possible with quartz gauges makes them

the obvious choice for determining these

fluid contacts (figure 3.4). Conventional

quartz gauges, however, require long sta-

bilization periods when subjected to sud-

den pressure and temperature changes,

such as those encountered during the

pre-testing of oil and gas wells.

Strain gauges have a better dynamic

response (i.e. they give a stable reading

much sooner) than the conventional

quartz gauge. However, they are not

accurate enough for most fluid gradient

determinations. The CQG offers the

dynamic behaviour of the strain gauge

coupled with the accuracy of a quartz

gauge (figure 3.5).

The CQG owes its exceptional

dynamic response to the fact that temper-

ature and pressure measurements are

made with a single quartz resonator. This

breakthrough was achieved by forcing

the resonator to oscillate simultaneously

in two different modes (frequencies). One

mode is dominantly pressure-sensitive,

while the other is influenced mainly by

temperature. This means that the adia-

batic effect introduced by pressure varia-

tion is immediately sensed by the

temperature mode and automatically

In this case the operator decided

that a wireline testing tool was required

to help identify these key contacts. It

was expected that the reservoir would

provide very few opportunities for

packer seats. Home Oil decided that

any data which could be gathered

should be of the highest quality. The

MDT tool was run with two H2S sample

chambers, the single probe module and

the Optical Fluid Analyzer (OFA*).

In this case the MDT tool recorded

data which allowed engineers to deter-

mine the reservoir fluid contacts and

captured representative fluid samples.

x474.8

x474.6

x474.4

x474.2

x474.8

30 60 90 120 150 30 60 90 120 150

x474.6

x474.4

x474.2

x474.8

x474.6

x474.4

x474.2

x474.8

x474.6

x474.4

x474.2

Delta time secDelta time sec

Pre

ssur

es

(R

aw a

nd s

moo

thed

) p

sia

Pre

ssur

es

(R

aw a

nd s

moo

thed

) p

sia

(a) (b)

47Number 16, 1996.

One wireline testing technique involves

the collection of numerous point pressure

measurements to establish a pressure gra-

dient which defines reservoir fluid type.

The restrictions imposed by limited preci-

sion in strain gauge measured pressures

and uncertainty related to depth, have, in

the past, confined this technique to thick

reservoirs.

A high-precision quartz gauge intro-

duced in 1980 allowed gradients to be

measured in thinner beds, but depth

placement uncertainty and long stabiliza-

tion times made this unattractive.

By running fast-response, high-preci-

sion quartz gauges, the MDT tool has over-

come the stabilization delay inherent in

previous quartz gauges. The tandem

assembly (figure 3.6b) removes depth

uncertainty because the separation dis-

tance is fixed. Reservoir fluid density can

be determined over 8 ft thick intervals or

even 2.3 ft intervals, when conditions are

favourable.

A new technique, which compensates

for the uncertainty between the paired

gauges by normalization to a downhole

measurement of the mud pressure gradi-

ent, allows the operator to double the

number of pressure points obtained at

each station, offering a major time saving

on traditional contact determination

methods.

Using this method, reservoir fluid den-

sity can be quickly and accurately deter-

mined over short intervals (table 1). This

provides a direct hydrocarbon determina-

tion independent of water resistivity (Rw)

invasion or lithological model.

The emergence and refinement of new

techniques indicate that log analysts are

determined to explore the full potential of

the MDT tool.

IT TAKES TWO TO TANDEM

Station (ft) Log Pressure derived fluid

interpretation density (g/cc)

A x390 Oil 0.6

B x446 Oil 0.4

C x452 Oil 0.5

D x457 Oil 0.4

E x465 Oil 0.6

Oil-water

contact

F x539 Water 0.9

G x573 Water 1.0

Table 1: Multiple

stations and the

interpretations based

on readings from

quartz gauge and

strain gauge spaced

2.3 ft apart.

Pressure (psi)

550 450

Dep

th(f

t)

x425

x550

650

x575

x700 x700

x825

GAS

OIL

WATER

Fluid density from pressure gradient (g/cc)

0.6

0

1.2Gas - oil - water

Fluid density from pressure gradient (g/cc)

0.6

Gas

Oil

Water

OIL

0

X450

X575

1.2

WATER

2.3ft

Table 1 - Fluid density determinations

Sour gas exploration/development

calls for special evaluation techniques,

and in a climate of growing environmen-

tal awareness, restrictions on acid gas

flaring can severely limit production

tests.

The quality of the MDT tool results

allowed the operator to cancel an expen-

sive production test. Home Oil consid-

ered the quality samples and fluid con-

tact determination provided by wireline

formation testing an effective and afford-

able alternative to production testing.

The MDT tool can contribute to well-

site safety and help to protect the envi-

ronment. These issues are particularly

important when production tests on sour

gas are to be carried out in populated or

environmentally sensitive areas.

Fig. 3.6: TANDEM PRESSURE

GAUGES: A large number of

single probe pressure

measurements (left) allow the

reservoir gradient to be

established statistically. These

gradients (or fluid density)

indicate the fluid type present.

When a quartz gauge and a strain

gauge are used together (below),

with a spacing of just 2.3 ft, the

vertical resolution improves

significantly. These examples are

plotted with the same depth scale.

Two quartz gauges would have

given even greater precision.

(a)

(b)

48 Middle East Well Evaluation Review

0

1800

2400

3000

3600

4200

4800

Pre

ssur

e, p

sig

0Time (sec)

Pre-test chamber volume: 20.1cc Gauge: BSG1 Res: 0.040psi

Depth: X586.08 ft

Mud Pressure before test = 4762.12 psig Mud Pressure after test = 4761.44 psig Last build-up pressure = 3893.20 psig Drawdown mobility = 8.9 md/cp

600 900 1200 1500 1800 2100 2400

Resistivity, ohm

m

0

30

24

18

12

6

Fig. 3.7: PUMP,

THROTTLE AND

SAMPLE: After pumping

9 litres of mud filtrate in

this well, the flowline

resistivity cell (black

line) shows an increase.

The pumpout module

was stopped and

reservoir fluid directed

into a sample chamber.

During sampling, the

throttle valve keeps

sampling pressure

around 3500 psia (red

line). When opened at

the PVT laboratory, the

sample chamber was

found to contain

hydrocarbon gas and

500 cc water.

Fig. 3.8: SWEEPING

CLEAN? Two openhole

log evaluations using

the original formation

water and sample water

resistivity. In this Middle

East example, the

pumpout module was

used to displace the

mud filtrate and sample

the water, which

proved to be a mixture

of formation and

injection water. Log

evaluation based on

formation water

resistivity suggests poor

sweep efficiency. When

the actual water

resistivity (measured

using the MDT tool)

was substituted in the

equation, a more

accurate and

encouraging result for

sweep efficiency was

obtained.

SW for RW = .018 (PU)0 100.00

GR0 100

1:500ftSW for RW = .047

(PU)0 100.00

Oil (RW = .047)SW for RW = .047

(PU)

0 100.00

Water

Electronic power module

Hydraulic power module

Power module

Sample module

Sample module

Pumpout module

Oil (RW = .018)

Clean sampling at a rangeof depths

One of the main objectives for wireline

formation testers has always been, and

will continue to be, reservoir fluid sam-

pling. Conventional tools can collect up

to two samples with each run into the

borehole. Unfortunately, the quality of

these samples is often impaired by the

presence of mud filtrate associated with

invasion during drilling.

Conventional wireline testers cannot

evaluate the purity of fluid entering the

chamber during sampling. The chambers

have to be returned to the surface before

the operator can determine whether or

not the samples are useful.

The MDT tool has overcome these dif-

ficulties - up to 12 sample chamber mod-

ules can be connected to the tool.

However, weight limitations (determined

by well conditions and cable strength)

generally restrict the number to six. The

multi-sample module contains a set of six

chambers, each with a 450 cc capacity,

and so can provide additional fluid sam-

ples during a single trip. This flexibility

allows the operator to sample at a vari-

ety of depths and produce a profile of

the reservoir’s fluid properties. The sur-

face unit can use the resistivity cell on

the probe module, or the Optical Fluid

Analysis module, to identify fluids (mud

filtrate, oil, water and gas) before taking

samples. The resistivity cell often has dif-

ficulties in identifying fluids when a well

has been drilled in oil-based muds and

may, in some cases, be unable to differ-

entiate oil from gas. The optical fluid ana-

lyzer has been designed to cope in these

circumstances, identifying mud filtrate,

oil, water and gas quickly and accu-

rately.

The final obstacle to the collection of

clean samples is mud filtrate invasion

into the formation. Fortunately, the MDT

tool has a solution. Mud filtrate can be

displaced by the pumpout module, a

miniature downhole pump which

pushes unwanted fluids into the bore-

hole before sampling begins.

Bubbles and dew

Having eliminated contaminants such as

mud filtrate from the sample our atten-

tion turns to the sample itself. To obtain

the high-quality samples suitable for PVT

we must avoid phase changes during

sampling.

Throttle valves prevent gas flashing

or liquid dropout during sampling. These

valves, under the control of the surface

49Number 16, 1996.

CO C C C i-C n-C i-C n-C C C 2 1 2 3 4 4 5 5 6 7+

Sample 1

Sample 2

Sample 3

Sample 4

Com

pone

nt %

0.01

0.1

1

10

100

Component

Fluid flow OilGas

Gas detectorLamp

Liquid detector

Light-emitting diode

Water

computer, automatically keep the sam-

pling pressure above a specified value to

ensure representative samples, limiting

drawdown during sampling. A key factor

in achieving a small drawdown is the for-

mation mobility: the best control over

sampling drawdown is achieved in high

mobility formations.

Another sampling application is the col-

lection of pure formation water samples.

The tool’s pumpout capability has pro-

vided, for the first time, the means to cap-

ture pure water samples in situ.

Pumpout in action

A sample taken from a reservoir in the

United Arab Emirates provides a clear

example of the effectiveness of the

pumpout module. Figure 3.7 shows the

pressure at the flowing probe along with

the flowline resistivity curve.

After pre-testing the formation, the

pumpout module is used to pump fluids

from the formation into the wellbore.

The low resistivity of the fluid indicates

that mud filtrate is being pumped. After

pumping approximately 8 litres, a spike

develops in the flowline resistivity

curve, indicating hydrocarbon flow.

At this stage, the pumpout operation

is halted and a sample chamber opened.

During sampling, the resistivity curve

confirms a hydrocarbon sample. This

real-time fluid identification eliminates

the uncertainty and time wasted by con-

ventional sampling.

Sweeping statements

Formation water resistivity is a vital input

for open-hole log analysis. Waterflood

sweep efficiency in a Middle East reser-

voir was calculated using water resistiv-

ity data based on MDT tool samples.

Initial estimates of sweep efficiency using

open-hole logs were hampered by the

mixed salinity of water in the formation.

A very pessimistic view of sweep

effectiveness was obtained using the ini-

tial connate water resistivity value of

0.018 Ω/m. The MDT tool was set at

x168 ft and, after pre-test, the pumpout

module produced 27 litres of fluid from

the formation. Once the pumpout opera-

tion had been completed, a one-gallon

(approximately 3.8 litres) sample cham-

ber was opened to collect the formation

water sample. The pumpout then

pumped an additional 5.3 litres into the

wellbore before a 450 cc water sample

was collected in one of the multi-sample

module’s bottles. Analysis of the water

samples collected in this way indicated a

water resistivity of 0.047Ω/m. Open-hole

log analysis using this new value offered

a much more accurate (and optimistic)

view of the waterflood (figure 3.8).

Fig. 3.10: The Optical

Fluid Analyzer has a

two-sensor system

which allows it to

detect and analyze

liquids and to detect

gas. This allows high-

quality oil and gas

samples to be diverted

into the sample

chambers after mud

and mud filtrate have

been pumped through

the system.

Fig. 3.9: FOUR OF A KIND: The results of PVT compositional analysis on four samples from

the same reservoir indicate a strong degree of similarity between the samples.

The multi-sample module has six

450 cc chambers. These chambers can

be transported without fluid transfer at

the wellsite. Drawdown during sampling

can be controlled by throttling valves

and water cushions.

If every MDT tool sample consists of

representative reservoir fluids, duplicate

samples from a particular depth should

show identical compositions. Four sam-

ples, recovered from a reservoir fluid in

near critical conditions, are shown in fig-

ure 3.9. These samples were obtained

with a maximum drawdown of just 8 psi,

thanks to water cushions, the throttling

valve and high formation mobility. The

sample chambers are designed to allow

transport of the samples to a PVT labora-

tory, without transferring the sample to a

shipping bottle. The compositional analy-

sis of the four samples, as well as other

fluid parameters (such as flash gas/liquid

ratios, bubble point and tank liquid den-

sities) show excellent agreement con-

firming the validity of the samples. In the

past, a large proportion of tests

attempted to sample unsuitable zones.

The new MDT tool offers us the chance

to examine the fluid before we collect it.

This sample ‘preview’ capability means

that the correct fluids will be brought to

the surface for analysis (figure 3.10).

50 Middle East Well Evaluation Review

Perfect permeability

Core permeability measurements have

long been focused on calculating hori-

zontal values, with vertical permeability

values often missing or hard to obtain.

Good samples for permeability evalua-

tion are often made on good core sec-

tions. The worst core sections - the parts

which represent barriers to vertical fluid

movement - have been under-sampled

or ignored. Vertical permeability can be

determined by a single well transient

test, provided that both spherical and

radial flow regimes are observed, or by

using a packer to isolate the zones in

question and conducting a vertical inter-

ference test.

Pre-testing with the MDT tool’s 20 cc

chamber gives a value for drawdown

mobility for each test. These values

reflect a combination of horizontal and

vertical mobilities, often referred to as

the ‘spherical mobility’.

The separate vertical and horizontal

components cannot be distinguished

from pre-tests and the small amount of

Flow rate, cc/sec

Pressure at the vertical probe, psia

Time (sec)Flow into sink probe

Pressure at the horizontal probe, psia

Fig. 3.11a: STEP ONE: A multiprobe test carried

out by the MDT tool acquires pressure data at

horizontal and vertical probes. Flow rate data

is either measured directly by the flow control

module or calculated from the pumpout or

sampling process.

Fig. 3.11b: STEP TWO: The pressure changes,

plotted against time at both probes, are used to

construct a flow regime identification plot. This

involves pressure-pressure deconvolution and

produces a derivative plot similar to that

obtained from a well test. Spherical flow is the

most common regime, with a slope of -0.5 on

the derivative curve.

Pre

ssur

e de

rivat

ive

Time (sec)

Spherical flow slope = -0.5

Horiz. mobility = 5.46 md/cp Vert. mobility = 2.58 md/cp Phi*Ct = 1.42E-06 (1/psi)

1/ time (sec)0.00.250.50.751.01.251.51.752.0

Del

ta -

pre

ssur

e (p

si)

Spherical Analysis Deconvolved vert. pressure Deconvolved horiz. pressure Pressure at vertical probe Pressure at horizontal probe Flow rate

Fig. 3.11c: STEP

THREE: For spherical

flow, a spherical time

function plot is

generated. This is

achieved by using

pressure-rate

deconvolution to

obtain first estimates

for horizontal and

vertical mobilities and

the porosity-

compressibility

product. For an infinite

medium, the maximum

pressure change at the

vertical probe is

inversely proportional

to the horizontal

mobility. The arrival

time of the pressure

disturbance is a

function of vertical

diffusivity.

fluid withdrawn from the formation

means that the drawdown mobility esti-

mate applies to a relatively small area

around the probe. The danger of sam-

pling small areas is that they may be

affected by formation damage close to

the probe, gas breakout in tight forma-

tions, fines migration and probe plugging.

51Number 16, 1996.

A larger withdrawal and the use of

more than one probe eliminates most of

these near-probe effects, allowing us to

evaluate important formation properties

on a larger scale. These include horizon-

tal and vertical mobility (which is perme-

ability divided by viscosity), and the

porosity-compressibility product.

Four steps to findingformation properties

Using the dual probe module, the single

probe module and the flow control mod-

ule, repeated vertical interference tests

can be performed along the wellbore.

The flow control module takes 1 litre of

formation fluid into a chamber, displac-

ing a piston in the process.

During the test, flow rates are moni-

tored (figure 3.11a). Acquired flow rate

and pressure data from the observation

probes can be analyzed to yield forma-

tion properties. The pressure change at

the probes is used to construct a flow

regime identification plot (figure 3.11b).

For spherical flow, a spherical time func-

tion plot is generated by using pressure-

rate deconvolution to estimate the

horizontal and vertical mobilities (figure

3.11c). The best match between

observed and calculated pressures is

obtained by using a model coupled to a

parameter estimator (figure 3.11d).

The multiprobe configuration has

been used offshore in the Middle East to

quantify vertical communication

through calcite and dolomite zones. The

openhole logs and test locations are

shown in figure 3.12. Four tests were

conducted in this well using one single-

and one dual-probe module. The flow

rate sources were both pumpout and

flow control modules. Tests 1 and 3

showed no response at the vertical

observation probe which was 2.3 ft

above the active (or sink) probe. This

indicates that a geological feature is act-

ing as a barrier for the duration of the

test.

Fig. 3.11d: STEP

FOUR: In an effort to

get the best match

between observed

and calculated

pressures the initial

estimates are used in

a model coupled to a

parameter estimator.

The final match is

shown using

pressures at the

horizontal and

vertical probes.

VerificationsReconstructed horizontal Pressure at horizontal probe Reconstructed vertical Pressure at vertical probe Flow rate

0

-15

0

15

30

Del

ta-p

ress

ure

(psi

)

Flo

w r

ate

(cc/

sec)45

60

75

-3

0

3

6

9

12

15

40 80 120Delta-time (sec)

160 200 240 280

Horiz. mobility = 5.34md/cp Vert. mobility = 2.78md/cp Phi* Ct = 1.96 E-06 l/psi

BS

Pump out

MUD CAKE From CALI to BS

Gamma ray (GR) (GAPI)

Caliper (CALI) (IN)

Bit size (BS) (IN)

Tension (TENS) (LBF) Neutron porosity (NPHI)

(V/V)6.0 16.0 0.02000.0

0.45 -0.15

6.0 16.0PhotoElectric Factor (PEF)

(.....)6.0 16.0Bulk Density Correction (DRHO)

(G/C3)6.0 16.0

0.0 100.0Bulk Density (RHOB)

(G/C3)

RHOB-NPHI from RHOB to NPHI

0.0 100.0

Test 2 kh/µ = 47.1md/cp kv/µ = 18.8 md/cp

φc = 1.97 x 10 /psit

-6 -1

Test 4 kh/µ = 33.0 md/cp kv/µ = 11.0 md/cp φc = 5.00 x 10 /psi

t

-7 -1

Multiprobe test 2

Multiprobe test 4

Flow control & pump out

Multiprobe test 3, two attempts

Multiprobe test 1, two attemptsFlow control and pump out

Flow control

Fig. 3.12: This

example shows the

results of some

multiprobe tests. In

this carbonate

reservoir, the

objective was to

quantify vertical

communication

across dolomitic and

calcite-rich zones.

Test locations are

marked on the

openhole logs.

52 Middle East Well Evaluation Review

Delta-time (sec)

Del

ta-p

ress

ure

(psi

)

Flo

w r

ate

(cc/

sec)

0 40 80 120 160 200 240 280 320

6.0

5.0

4.0

3.0

2.0

1.0

0

-1.0-1.5

0.0

1.5

3.0

4.5

6.0

7.5

VerificationsReconstructed horizontal Pressure at horizontal probe Reconstructed vertical Pressure at vertical probe Flow rate

Horiz. mobility = 33md/cp Vert. mobility = 2.78md/cp Phi*Ct = 5E-07 l/psi

Fig. 3.13: FLOW

CONTROL TEST:

Rates from the flow

control module,

observed and

simulated pressure

responses at both

probes during test 4

(see figure 3.12).

Fig. 3.14: FOUR PROBE FASHION: This

configuration, popular in some parts of the

Middle East, is intended to quantify vertical

communication across thick zones which are

believed to be flow barriers.

Vertical probe 2

Vertical probe 1

Sink probeHorizontal probe

Moblility V2 (MD/CP)

0.0 20.0

Formation Pressure V2 probe (psia)

2800.0 3000.0

Formation Pressure V1 probe (psia)

2800.0 3000.0

Moblility, V1 (MD/CP)

0.0 20.0

Moblility, Sink probe

0.0 20.0

Moblility, Hor. probe (MD/CP)

0.0 20.0

Formation Pressure Sink probe (psia)

2800.0 3000.0

Formation Pressure Hor. probe (psia)

2800.0 3000.0

Fluid %

50 (PU) 0

Porosity and Fluid Analysis by Volume

Unmoved

Moved

Water

Clay

Dolomite

Limestone

Porosity

Anhydrite

Formation Analysis by Volume

Matrix %100 (PU) 0

Multiprobe Test -1 Across D2

Multiprobe Test - 2 Across D2-A

Multiprobe Test - 3 Multiprobe Test - 4

Across D3x200

Fig. 3.15: The four probe

MDT configuration was

used at four locations in

this well. The objective

was to quantify vertical

communication across

stylolitic zones. Stylolites

are thin, irregular rock

boundaries which

develop in some

limestones (and

evaporites). They are

caused by pressure

dissolution and re-

deposition of existing

sedimentary material.

Tests 2 and 4 produced responses at

both monitor probes. Test 2 used the

pumpout module as the flow rate source.

Test 4 was conducted through the

sink probe, using the flow control mod-

ule. Figure 3.13 shows the flow control

rates and observed and simulated pres-

sure responses at the monitor probes.

The results from these tests show that

the vertical permeability is about one

third of the horizontal permeability. This

information will help reservoir engineers

to set up their reservoir simulation

model.

Sometimes, operating companies need

to know the extent of vertical communica-

tion across suspected barriers. Thick bar-

riers can be accommodated by increasing

the spacing of the multiprobe from 2.3 ft to

10.3 ft with the addition of a fourth probe.

In this configuration the spacing between

53Number 16, 1996.

two vertical probes is 8 ft. This arrange-

ment (figure 3.14) has not been widely

used in the Middle East.

In this recent test, the configuration

was used onshore, with all three flow

rate sources (flow control, pumpout and

sample chamber modules). The objec-

tive was to identify the barrier properties

of stylolite horizons in a carbonate

sequence. The four tests carried out on

these horizons are presented in figure

3.15.

The Fullbore Formation MicroImager

(FMI*) images for the zones where test 3

and test 4 were carried out are shown in

figure 3.16. The probe locations are

clearly indicated on these images.

Fig. 3.16: These FMI

images from tests 3

and 4 (see figure 3.15)

show the type of

heterogeneity which

cannot be fully

identified using

openhole logs. These

images, taken after the

MDT survey, show the

exact position of each

probe during the

survey.

In test 3, a 3.5 litre volume was

pumped - causing a pressure drop at the

first vertical probe. The test continued

with activation of the pumpout module

from the first vertical probe. However,

the probe was situated in a tight zone

and the tool was reset for test 4.

The tool was moved 0.6 ft down the

well before the start of test 4. The first

vertical probe was activated, pumping

10.5 litres of formation fluids. A pressure

drop of 0.7 psi was observed at the sec-

ond vertical probe.

x188.0

x190.0

x192.0

x194.0

x196.0

x198.0

x200.0

x125

x150

x175

x200

54 Middle East Well Evaluation Review

Figures 3.17 and 3.18 show the

recorded and modelled responses at

vertical and sink probes. Results from all

of the transients are summarized in

Table 2. Note the response seen at the

vertical probe, in test 1, which was 10.3 ft

above the sink probe.

Mini drillstem tests

Defining pressure points for fractured,

vuggy, very tight or highly-laminated for-

mations has often presented problems

for wireline formation testers.

The dual packer module available

with the MDT tool provides a much big-

ger flow area - isolating 3 ft of formation

between two inflatable packers. The area

open to flow is then three orders of mag-

nitude larger than a conventional probe.

This allows larger flow rates and less

drawdown than can be achieved with

the probe.

Tests conducted with the dual packer

module can be thought of as mini drill-

stem tests on wireline. The radius of

investigation may reach tens of feet in a

test completed within a few minutes.

The Dual Packer Module helps to

overcome the testing problems encoun-

tered in highly fractured reservoirs. FMI

tool and Ultrasonic Borehole Imager*

(UBI) tool images (figure 3.19) were

used to identify a suitable test zone

which contains a fracture. A log-log plot

of pressure and pressure derivative and

a generalized superposition plot (figure

3.20) show measured data and the simu-

lated pressure response produced by

the Schlumberger ZODIAC* (Zoned

Dynamic Interpretation Analysis and

Computation) well testing package. The

correlation between measured and theo-

retical data is excellent.

pressure at sink probereconstructed sink

horiz. mobility = 1.4 md/cp

vert. mobility = 1.5 md/cp

phi*Ct = 1.06E-06 1/psi

0

54

48

42

36

30

24

18

12

6

0200 400 600 800 1000 1200 1400 1600 1800

Delta - time (sec)

Del

ta -

pre

ssur

e (p

si)

Fig. 3.17: THE VERTICAL MATCH: The response at the vertical probe, 8 ft above the active probe,

was matched using a homogeneous model. The reservoir parameters are presented in Table 2.

Fig. 3.18: SINK MATCH: During the pumpout test from the first vertical probe, the sink probe, 2.3 ft

below, acts as an observation probe. The figure shows the pressure match at the sink probe. The

reservoir properties are presented in Table 2.

Table 2: Summary of reservoir properties

Test kh/µ, md/cp kv/µ, md/cp φct, 1/psi

1 (2.3 ft) 11.1 5.20 1.41E-06

2 (2.3 ft) 5.20 0.70 1.30E-06

2 (10.3 ft) 12.0 0.30 2.00E-07

3 (2.3 ft) 1.60 1.90 1.03E-06

4 (2.3 ft) 1.40 1.50 1.06E-06

4 (8 ft) 21.9 0.15 3.00E-07

0.000

0.070

0.140

0.210

0.280

0.350

0.420

0.490

0.560

0.700

0.630

0 200 400 600 800 1000 1200 1400 1600 1800

Delta - time (sec)

Del

ta -

pre

ssur

e (p

si)

response at vertical 2reconstructed vertical 2

horiz. mobility = 21.9 md/cp

vert. mobility = 0.153 md/cp

phi*Ct = 3.0E-07 1/psi

55Number 16, 1996.

Fig. 3.19: Using the UBI (left) and FMI (right)

tools, suitable test zones can be selected and

tested (essentially a ‘mini drillstem test’) using

inflatable packers.

Wellbore storage using the MDT tool

is five orders of magnitude smaller than

a conventional DST. This allows full

characterization of the tested interval

after only 6 minutes of shut-in. These

‘mini DSTs’ are more efficient than con-

ventional DST tests and offer additional

advantages in relation to environmental

and safety issues.

Formation testing has come a long

way in the last 40 years. Sophisticated

pressure measurement and fluid

retrieval have become commonplace,

but, as always, the quest continues for

more information, gathered faster and

with greater accuracy.

Pressure Change

Log-log plot

100

101

102

103

10-4

10-3

10-2

10-1

100

∆ t (hr)

∆ t (h )

10-4

10-3 10

-210

-110

0

∆p a

nd d

eriv

ativ

e (p

si)

Pressure derivative

Radial Flow Regime

Superposition Plot

400

300

200

100

0

∆p(p

si)

The next step in the evolutionary pro-

cess of formation testing will be deter-

mined by the operators. The RFT tool,

after all, was designed primarily for fluid

sampling, but its pressure measurement

capabilities were generally considered

more important.

As the MDT tool replaces older sys-

tems, log analysts will find ways to

exploit the new technology and will ulti-

mately control the way in which this

powerful new system is developed.

Fig. 3.20: This figure

shows the log-log plot

of pressure and

pressure derivative

and a generalized

superposition plot for

both measured and

simulated pressure

response. Note the

excellent match

which has been

obtained using

conventional pressure

transient techniques.