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ADVANTAGES AND LIMITATIONS OF TAKING SAMPLES WHILE

DRILLING

Ansgar Cartellieri, Jos Pragt, Matthias Meister

Baker Hughes

Copyright 2012, held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors

This paper was prepared for presentation at the SPWLA 53rdAnnual Logging Symposium held in Cartagena, Columbia, June 16-20, 2012.

__________________________________________________________________________________

ABSTRACT

What are the advantages and where are the limitations of fluid analysis and sampling while drilling tools? There arecurrently two main questions that are discussed in the community. Will it be possible to achieve the same sample

quality with one of the new fluid analysis and sampling tools for while-drilling applications as with currently

available wireline technology? And will it be possible to achieve this after a shorter pump-out time? Multiple

simulations were performed to see if it is beneficial to take samples as early as possible after the drilling process, orif it is beneficial to have a completely formed mud cake. In this paper the different aspects of this query will be

discussed by a case study.

Compared to the widely used wireline formation testing tools, the first generation of logging while drilling tools is

equipped with less complex measurement technologies. This is due to the rough drilling environment, where the very

sensitive measurement technology and actuator systems have to be protected more carefully. The limited

measurement technology is mainly used for clean-up estimation rather than for fluid identification. Current

measurement technologies besides pressure and temperature in sampling while drilling tools are density, viscosity,

sound speed and refractive index, but are not limited to these. On the other hand, a much more sophisticated pumpand pump control system is necessary due to the slow surface communication via mud pulse telemetry. A closed-

loop control system and different intelligent algorithms avoids pumping below the bubble point and thus the

alteration of the fluid sample. The build in computing power of the tool itself needs to be much higher for thecomplex control of the pump and measurement technologies.

In this paper a case study and the capabilities of this new LWD fluid analysis and sampling tool will be shown. It

will be discussed if the theoretic advantages of taking samples while drilling, like a higher sample quality with less

contamination or a shorter pump-out time due to less invasion, could be proven. The paper will show that it is

possible to run such a complex service in a nearly autonomic system. The continuous interaction of the operator with

the system to control the pump will not be necessary. This gives the operator more freedom to monitor and interpret

the sensor readings.

FUNDAMENTALS

The reservoir characterization is one of the most important aspects in assessing the potential for hydrocarbon

delivery. The description of the reservoir is based on the reservoir fluid and petrophysical properties. A

comprehensive reservoir characterization encompasses three main points. The first is the characterization of the fluidand pressure profile. This is mainly provided by wireline services, but in the recent years also from pressure-testing

tools for while-drilling applications (Meister, 2003). In the last two years logging while drilling (LWD) reservoir

sampling tools have added a new dimension to evaluation planning and reducing the overall data uncertainty (Proett

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2010; Villareal, 2010). The second aspect is the pressure, volume and temperature data in combination withgeochemical and log data. This is gathered from different wireline and while-drilling logging services as well as the

data evaluation of different samples in a laboratory. The third point is the core and mud log analysis based on

continuous monitoring of the mud properties and coring operations during the drilling campaign. Together with the

petrophysical model of the reservoir these aspects should deliver the whole picture of the reservoir conditions, size

and producibility.

The information gathered by the different models and measurements are critical for the whole production life cycle.Decisions regarding completion design, production facilities design, and development strategies depend on an

accurate reservoir description. Currently, in a typical life cycle of a well the most critical phases are exploration andappraisal. During these phases the data obtained from measurements are combined and integrated into a study to

reduce uncertainty and to assess the reservoir delivery, size and compartmentalization. The petrophysical propertiessuch as porosity and permeability are evaluated and their relationship and saturation is calculated. From different

measurements like fluid identification and sampling the hydrocarbon type its recoverable composition and the phase

behavior are derived. Based on these data the top-side facility design and transportation means will be discovered.

The production rate and the market valuation of the hydrocarbon type deliver the profitability of the reservoir. Beside

this, and due to the increasing energy demand in combination with a decreasing number of new discovered

reservoirs, the reentry and expanded depletion of already produced fields becomes more and more important. There

you need to evaluate the risk of water or CO2production with decreasing reservoir sizes and the use of sea water or

CO2as injection fluid.

Increasingly complex well designs and reentries in produced fields increases the risk of wellbore issues and makes it

more necessary to run the wireline fluid identification and sampling tools on pipe or with a tractor system. This is the

arena for the introduction of the new developed sampling while drilling tools. This mitigates the risks of samplingand testing in extremely deviated or horizontal wells and delivers answers early after the drilling campaign in

comparison to wireline operations. In the end there is increased reservoir knowledge and the possibility of analyzing

the downhole fluid properties while drilling and in real time.

TOOL DESCRIPTION

The tool described in this case study delivers real-time downhole fluid analysis and samples as well as formationpressure and mobility data while drilling. Pressure measurements are continuously taken in the drilling process to

enhance the drilling efficiency and improve the wellsite safety. The tool uses a combination of a closed-loop sealing

system and an intelligent testing sequence to ensure reliable formation pressure and mobility data for better real-time

decisions (Meister, 2004a). Due to the low bandwidth of a mud pulse system in a while-drilling environment it is not

possible to communicate continuously with the tool. To overcome this challenge a highly sophisticated pump andseal control system is integrated. This system uses several intelligent algorithms to avoid pumping below the bubble-

point and prevent alteration of the fluid sample.

In addition to the early investigation of the reservoir this tool enables fluid sampling and analysis for enhanced

understanding of the reservoir through fluid properties in wells where testing was previously considered either too

risky or costly. It is now possible to do full formation testing in all deviated and horizontal wells including extended-

reach and deepwater drilling campaigns. To monitor the sample contamination for clean fluid sampling multiple

sensors are included. To confirm and correlate the pressure gradients a direct density measurement is integrated. Thisalso enables the accurate fluid analysis of reservoir connectivity and compartmentalization and fluid typing for an

improved producible reserves estimate. The real-time permeability measurement is based on mobility and in-situ

viscosity evaluation (Reittinger, 2008). Additional sensors like the continuous refractive index, the temperature and

the sound speed measurement provide real-time downhole fluid identification and analysis (Figure 1).

An improved drilling efficiency is given by reduced invasion of mud into the formation and thus less time to achieveclean samples. Based on the pressure measurements and the continuous updates of the pressure profile an equivalent

circulating density management reduces the formation damage as well as improves the wellbore stability. This

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enables an optimized mud weight for an increased rate of penetration, reduces the cost and risk through lessstationary time. The advanced drilling process provides enhanced wellsite safety and saves time and cost due to

eliminating the need for a wireline run.

Figure 1: Tool schematic

The fluid analysis and sampling tool for while-drilling applications incorporates the full formation pressure testing

functionality of tools that are already field proven for many years. It includes a continuous real-time pressure curve

during clean up and a pump-through capability with an accurate pump control and clean up monitoring for high

sample quality. It enables capturing up to 16 single-phase samples in a single run with H2S-resistant fluid lines and a

tank material that shows nearly no accumulation or diffusion of H2S (Cartellieri, 2011). Based on the fluid

identification and the samples taken while drilling, the reservoir knowledge could be increased significantly.

WELL BACKGROUND AND CHALLENGES

The current paper discusses the sampling operation in an exploration well in the southern North Sea drilled in an oil-and-gas-prone hydrocarbon province (Blom, 2008). Nearby appraised fields typically show a gas capped oil rim. The

current well was planned to intersect the prospect at a high angle. The future purpose of the well, if successful in

proofing sufficient quantities of hydrocarbons, would be re-entered and re-completed as a horizontal well targeting

an oil rim. Samples would need to be taken to prove the presence of hydrocarbons and the PVT characteristics. The

operator chose LWD sampling to mitigate the risks involved in deploying a wireline tool while conveyed on pipe.

The expected fluids consisted of (wet) gas, 40 API oil close to saturation pressure, and salt formation water at a

density close to 1.08 g/cc. The well would be drilled with an oil-based mud. The produced fluids from offset wells

were studied to complete a list of the possibly encountered fluids, and their PVT characteristics so that downhole

fluid identification would be possible. Though the reservoir pressure conditions were to be expected at normal

hydrostatic pressure, the drilling requirement for the 8.5-in. openhole reservoir was to intersect some reactive shales

just above the prospective reservoir. This would require a fairly heavy mud to control the less-stable shale section.

This, in turn, would increase the pressure overbalance whilst drilling the reservoir sands and most likely wouldincrease the depth of invasion so that extended volumes of mud filtrate would need to be pumped out of theformation prior to sampling representative reservoir gas, oil or water. In addition, the sampling run was planned as a

dedicated reaming run after the drilling of the section was completed. Sampling while drilling would have the

advantage of a shallower invasion and less pumping time to acquire a clean sample. As the current sampling run

would be more representative of a wireline job, it was expected that extended periods of fluid pump out and clean up

would be required.

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The reservoir quality was good with up to 20% porosity and permeability above 100 mD. Littlecompartmentalization was expected so that the fluid gradient should be representative of the density of the reservoir

fluids. The gradient results showed continuous fluid columns, though the presence of pressure barriers in the water

zone could not be fully excluded.

Following the drilling of the reservoir sections the LWD Triple Combo log showed the possible presence ofhydrocarbons. The section measured 1307m with inclination building from 45 to 68 degrees. The gamma ray showed

a long sandy section, with some laminations in place. The high resistivity indicated low water saturations over thetop of the sand zone. The neutron-density cross-over appeared to indicate the presence of light hydrocarbons.

Towards the base of the hydrocarbon zone the resistivity dropped off over what seemed to be a transition zone. Thiszone was the main target for the pressure test and sampling operation as a possible oil rim would be potentially

exploitable using horizontal wells. Further down the sand sequence, the water zone was characterized by lowresistivity, indicating a large aquifer.

Figure 2: BHA configuration with three tank carrier modules

After reaching final depth, which extended well into the water zone, the drilling bottomhole assembly (BHA) was

changed out for a LWD pressure test and sampling BHA (Figure 2). The sampling BHA included 12 sample tanks to

ensure all fluid types would be sampled and sufficient redundancy would be guaranteed. The assembly was run to

final depth, and then pulled out whilst measuring formation pressures and mobility at 25 stations. Following a reviewof the acquired fluid gradient with the geologist and reservoir engineer, three main fluid zones were identified and

four sampling stations were selected, of which two were in the transitional oil zone. Operations continued with the

first two sampling stations in the oil zone characterized with a fluid gradient of 0.64 g/cc. Based on the initial

pressure test acquisition, the depths with the highest mobility were selected. A high mobility ensures that pumping is

possible at a high rate without causing too much pressure drawdown which could cause degassing of the oil, or dew-point alterations of the wet gas. After collecting six oil samples, two samples were taken in the water zone, and three

samples in the upper gas zone. The gas zone was done last so as to minimize the risk of gas remaining in the sample

lines of the tool prior to taking other fluid samples. Gas remaining in the tool is possible when the well inclination isabove a 60 degrees angle. Nevertheless the tool has flushing capability engineered to flush the complete internal

flow-line with mud on request. If sample-cross contamination is critical and needs to be minimized a flushing cycle

can be performed with the tool downhole. During the pressure test and sampling operation the openhole section

showed formation instability and recorded mud losses which did not hinder the successful data acquisition.

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FIELD TEST RESULTS

The primary test objective was to acquire fluid samples to prove the presence of hydrocarbons and to verify the

functionality of the fluid analysis and sampling tool. The following test sequences were covered within this

operation:

Test capability of taking accurate pressure tests to establish pressure gradients (Meister, 2004b) Test clean-up and fluid analysis capability Test sampling capability (to retrieve low contamination samples)

Evaluate tool integration in a complex drilling and evaluation BHA

Establish best practice for operations procedure and verify draft procedures

Perform difficult sampling operation in an highly inclined well

Based on the gamma ray, resistivity, and bulk density log several test horizons were identified. Prior to starting thesampling, 18 pressure tests were conducted to obtain sufficient high-quality pressure data to construct a hydrocarbon

and water gradient and to estimate the oil/water contact. Figure 3 displays a pressure test with repeated drawdown

that indicates a mobility of 91.6 mD/cP (Strobel, 2005). The repeatability with exactly matching formation pressures

of x83.409 bar after the second and third drawdown proves the tool capability of acquiring accurate pressure tests.

Figure 3: Real-time display of a pressure test with repeated drawdown (91.6 mD/cP)

Based on the pressure tests conducted four different test horizons for the sampling operation were identified.

Especially the transition zone between the water and gas gradient was of interest because a small layer of an oil-

bearing reservoir was expected. Figure 4 illustrates the gamma ray, resistivity and bulk density log with the pressure

and sampling points (Shammai, 2012).

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Figure 4: Gamma ray, resistivity and bulk density log with the pressure and sampling points

Figure 5 demonstrates the pressure gradient analysis based on 25 pressure points taken during the entire operation.This includes the pressure values from the beginning of the six sample stations and an additional pressure test

performed in between. The analysis clearly identifies three distinct gradients for gas, oil, and water. Based on this

data, a gas density of 0.1505 g/cm3, an oil density of 0.6353 g/cm

3, and a water density of 1.099 g/cm

3were revealed.

Figure 5: Formation pressure against true vertical depth with gradients

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As illustrated in Figure 4, a clean-up operation was performed at stations 19, 20, 22, 23, 24, and 25. At the stations19, 20, 22, and 25 a total of eleven sample bottles were filled successfully. Table 1 shows a summary of the sample

stations with the measured depth (MD), true vertical depth (TVD), the best pressure test value based on the

formation rate analysis (Frank, 2004; Lee, 2000), the best mobility, and the number of samples taken. The first two

sample stations are located in the transition zone between gas and water where the gradient analysis indicates oil

with a density of approximately 0.635 g/cm

3

.

Table 1: Summary of the sample stations

Station MD TVD APresA Fpress (best) Mobility (best) Samples

# [m] [m] [bar] [bar] [mD/cP] #

19 x690.0 x862.0 x63.1 x83.5 161.6 3

20 x692.5 x862.7 x62.9 x83.5 143.5 3

22 x737.0 x875.8 x65.8 x84.8 198.6 2

23 x636.0 x846.0 x61.4 x83.2 99.9 0

24 x636.0 x846.0 x61.3 x83.2 83.2 0

25 x612.0 x838.9 x60.8 x83.1 1507.1 3

Prior to the clean-up sequence the tool always performs a pressure test. This ensures the tool achieves a good seal,

measure the formation pressure and retrieve the mobility of the formation. After the pressure test the toolautomatically begins a clean-up operation with a predefined maximum drawdown and maximum pump rate.

Depending on the mobility of the formation, the maximum drawdown or the pump rate limits the pump out. To avoid

degassing the drawdown pressure should be kept above the expected bubble point pressure at all times. After the

pressure goes below the bubble point gas will be produced from the formation fluid and the clean-up process isdisturbed. The gas is not only produced inside the tool but also in the formation. The risk is high that the higher

pump speed is counter-productive because of degassing. The time saved because of the higher flow rate could be a

disadvantage, compared to the time needed for getting rid of the produced gas. Thus, the recommendation should be

to always avoid pumping below the bubble point. When the maximum drawdown is set accurately the closed loop

pump control system makes it possible to run the tool in pressure-controlled mode well above the bubble point. Noreadjustment of the pump settings due to a changing mobility while cleaning up is necessary since this is handled

autonomous inside the tool. Figure 6 shows a pressure test with repeated drawdown and subsequent clean up. As

seen in Figure 3, the pressure test shows a repeatability of the second and third formation pressure of x84.813 bar

with a mobility of 198.7 mD/cP. The final pressure does not reach the annular pressure again as the tool directlystarts the clean-up sequence.

Figure 6: Pressure test with repeated drawdown (198.7 mD/cP) and subsequent clean up.

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During clean up the sensor readings are continuously send to surface and monitored on the surface display. Instandard drilling operations mud pulse telemetry is used for data communication between the surface and the BHA.

In comparison, wireline tools have an electric connection and communications channel suitable for interactive tool

control and operation. The operator interacts and monitors continuously the system and can adjust the different

parameters according to the downhole conditions.

Figure 7: Clean up and sampling of oil in the real-time display

Due to the low bandwidth of the mud pulse systems, this is hardly possible in the while-drilling environment.Therefore, intelligent algorithms like the closed loop pump control system are already implemented into the tool. In

addition, the low bandwidth makes it also more difficult to monitor the sensor readings and the cleaning process. The

resolution and the update rate are limited, compared to wireline or wired pipe operations. Figure 7 shows exemplary

the clean-up process at station # 20. The real-time display is adjustable according to the requirements. In this

example the clean-up process is illustrated over time in vertical columns. The first column contains the different tool

parameters like the current flow rate, the current pressure, the total volume pumped and the operating mode of the

tool. The incremental increase in the total volume pumped demonstrates the limited bandwidth. In this scenario the

resolution of the total volume pumped is 1.7 liters, whereas tool internally the resolution and update rate is much

higher. Two columns are showing the different sensor readings like the fluid temperature, the temperature difference,the sound transit time (reciprocal of the sound speed), the refractive index, the density, and the viscosity. The last

column illustrates the sampling process with tank number, the tank filling pressure, and the actual tank volume. Theinterpretation of the sensor readings in Figure 7 indicates the clean-up from oil-based mud filtrate to formation oil. In

while-drilling operations the clean-up process from mud to mud filtrate is often concealed by downlinking or theuplink of the pressure test data. Whereas the density and viscosity readings indicate stable values after approximately

20 minutes of pumping, the sound transit time as well as the refractive index are still decreasing and increasing,

respectively.

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Figure 8: Sampling process of oil in the real-time display

After more than 1.5 hours the first sampling command was transmitted covering the data readings during

downlinking. The increasing tank volume and tank pressure data in the right track indicate the tank-filling process.The tool measured a tank-filling volume of approximately 840 cm3for oil, 820 cm3for water, and 1.5 liters for gas

and a tank-filling pressure between 830 and 848 bar under downhole conditions. The varying filling volumes are

depending on the compressibility of the fluid. This indicates the tool needs diverging pump strokes to fill the tank

until the pump reaches its final pressure. At the end of each filling process the pump process stops for a couple of

seconds while over-pressuring the sample. This has no impact on the clean-up process as illustrated in Figure 8.

Figure 9: Clean-up trend from the tool internal memory annulus + formation pressure and flow line temperature

as well as density and viscosity of an oil sample

The evaluation of the memory data after the run is demonstrated in Figures 9 and 10. These figures clearly show the

much higher resolution of the sensor readings internally. On the annular pressure reading the downlink commandsfor starting the sample tank filling process are visible as well as the final pressure peak when over pressurizing the

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tank. The sampling process can also be observed by the temperature reading in the tool internal flow line. Thedensity measurement indicates a final value of approximately 0.7 g/cm3, which is still slightly higher than the

expected density of 0.64 g/cm3. The PVT analysis in an external laboratory after the run confirmed this value as the

contamination level was 21-23% for the first oil sample station.

Figure 10: Clean-Up trend from the tool internal memory sound speed and temperature difference as well as

refractive index and according fluid temperature of an oil sample

The memory readings of the sound speed and refractive index measurements in Figure 10 as well as the real-time

display in Figure 7 indicates decreasing values for the sound speed and refractive index, respectively. In combination

with the density reading of 0.7g/cm3 from the tuning fork it should have been realized that there is still residual

contamination in the samples and that the clean-up process was not fully finished.

Figure 11: Oil sampling and over-pressurization

Figure 11 demonstrates the oil-sampling process and over-pressurization. The utilized single-phase sample tank is

compensated to the annulus and includes a nitrogen buffer to avoid phase separation and asphaltene precipitation

while pulling out of hole. The figure shows the different strokes to fill up the tank within approximately 2.5 minutes

and the final over-pressure of 600 bar above formation pressure.

During 42 circulating hours, a total of approximately 1000 liters were pumped at four sample stations. Total time on

the wall for the first sample station was 140 minutes, for the second sample station 115 minutes, for the third station

170 minutes, and for the fourth station 220 minutes. The tank-filling procedure needs 2-6 minutes to fill the tanks

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after sending the sampling command. During the whole FAS operations no lost seal was observed. The final PVTanalysis delivers a contamination of 20% for the gas samples and below 5% for the water samples.

Table 2 compares the final contamination of a sampling-while-drilling run performed in the Caribbean Sea with the

wiper trip described in this case study. Time elapsed since drilled was 9 hours compared to 96 hours, whereas the

pump-out volume was 53 liters compared to 98 liters with a pump-out time of 2.5 hours compared to 4.5 hours.Nevertheless, the final contamination reached in the drilling run was much lower compared to the wiper trip. Hardly

any contamination was found in the final sample analysis of the gas sample. In both cases a high mobility of morethan 1000 mD/cP was measured. The only difference that could have improved the clean-up sequence in this

comparison is the use of a water-based mud system compared to the oil-based mud system from the case studypresented in this paper.

Table 2: Comparison of the sample contamination of two different LWD sampling runs

LWD

Sampling Run Run Type

Time elapsed

since drilled

Pump-out

volume

Pump-out

time

Sample Mud

contamination

# [hrs] [l] [hrs] [%]

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ECD Equivalent circulating density

FAS Fluid analysis and sampling

LWD Logging while drilling

mD Millidarcy

MD Measured depth

MWD Measurement while drilling

POOH Pull out of hole

psi Pounds per square inch

PVT Pressure volume temperature

TVD True vertical depth

ACKNOWLEDGMENT

The authors wish to thank Baker Hughes for their support in preparing and presenting the results achieved with the

new LWD fluid analysis and sampling tool.

REFERENCES

Cartellieri, A., Pragt, J. and Meister, M., 2011, Fluid Analysis and Sampling The Next Big Step for Logging WhileDrilling Tools, SPWLA 52nd Annual Logging Symposium, Colorado Springs, Colorado, USA, May 14-18.

Blom, F., Borren, L., van & Bacon, M., 2008, De Ruyter Field, Netherlands - Discovery and Near-Field Exploration.

European Association of Geoscientists and Engineers, 70th Conference and Technical Exhibition, Rome, Italy, June

9-12.

Frank, S., Beales, V.J., Dilling, S., Meister, M., Lee, J., and Haugen, J., 2004, Field Experience With a NewFormation Pressure Testing-During-Drilling Tool, IADC/SPE 87091, Dallas, Texas, USA.

Lee, J., and Michaels, M., 2000, Enhanced Wireline Formations Tests in Low-Permeability Formations: Quality

Control Through Formation Rate Analysis, SPE 60293 presented at the SPE Rocky Mountain Regional/Low

Permeability Reservoirs Symposium, Denver, Colorado, USA, 1215 March.

Meister, M., Buysch, A., Pragt, J., and Lee, J., 2004a, Lessons Learned from Formation Pressure Measurements

While Drilling, SPWLA 45th Annual Logging Symposium, Noordwijk, Netherlands, 6-9 June.

Meister, M., Lee, J., Krger, V., Georgi, D., Chemali, R., 2003, Formation Pressure Testing During Drilling:

Challenges and Benefits, SPE 84088, paper presented at the SPE Annual Technical Conference and Exhibition held

in Denver, Colorado, USA, 5 8 October.

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Meister, M., Pragt, J., Buysch, A., Witte, J., Nordahl, G., and Hope, R., 2004b, Pressure Gradient Testing with a newFormation Pressure Testing During Drilling Tool, SPE 90425 presented at the SPE Annual Technical Conference

and Exhibition, Houston, Texas, USA, 26-29 September.

Proett, M., Welshans, D., Sherril, K., Wilson, J., House, J., Shokeir, R. and Solbakk, T., 2010, Formation Testing

Goes Back to the Future, SPWLA 51st Annual Logging Symposium, Perth, Australia, 1923 June.

Reittinger, P.W., 2008, System and Method for Determining Producibility of a Formation Using Flexural Mechanical

Resonator Measurements, United States Patent Application Publication, USA, 2008/0215245 A1

Strobel, J., Bochem, M., Doehler, M., Meister, M., Buysch, A., Pragt, J., Schrader, H., 2005, Comparison of

Formation Pressure and Mobility Data derived during Formation Testing While Drilling with a Mud Motor with

Production Data and Core Analysis, SPE/IADC 92492, Amsterdam, The Netherlands, 23-25 February.

Villareal, S., Pop J., Bernard, F., Harms, K., Hoefel, A., Kamiya, A., Swinburne, P. and Ramshaw, S., 2010,Characterization of Sampling While Drilling Operations, IADC/SPE 128249, New Orleans, Louisiana, USA, 24February.

Shammai, M., 2012. The Role of LWD Pressure Testing & Sampling in Reservoir Characterization, SPE Applied

Technology Workshop: The Changing Role of Petrophysics in Characterizing and Producing Middle EastReservoirs: Uncovering What is Myth and What is Reality?, Dubai, UAE, 20-22 February.

ABOUT THE AUTHOR

Ansgar Cartellierihas a PhD in chemical engineering from the Helmut-Schmidt-University Hamburg. He has been

working as R&D engineer on new sensor technologies and data analysis for downhole fluid analysis. Currently, he

leads the LWD fluid analysis and sampling development group at Baker Hughes.

Jos Pragthas a Diploma in geology and geophysics from the University of Utrecht. He has been working in BakerHughes as an MWD/LWD coordinator and field engineer in Europe. He was involved in the development of the

LWD formation pressure testing tool and currently works in the development group of the LWD fluid analysis andsampling tool.

Matthias Meisterhas a Diploma in mechanical engineering from the University of Hannover. After working for

Eastman Christensen and Hughes Christensen on MWD systems and diamond drill bits, he worked for Baker Hughes

as a project manager on LWD formation evaluation tools. Currently, he is the Product Development Manager for

formation testing and sampling, nuclear magnetic resonance, resistivity imaging, and seismic.

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