DOWNHOLE VISCOSITY MEASUREMENT: REVEALING RESERVOIR FLUID COMPLEXITIES AND ARCHITECTURE

Transcription

1 DOWNHOLE VISCOSITY MEASUREMENT: REVEALING RESERVOIR FLUID COMPLEXITIES AND ARCHITECTURE Vinay K. Mishra, Beatriz E. Barbosa (Schlumberger), Brian LeCompte (Murphy Oil), Yoko Morikami, Christopher Harrison, Kasumi Fujii, Cosan Ayan, Li Chen, Hadrien Dumont, David F. Diaz, Oliver C. Mullins (Schlumberger) Copyright 2014, 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 55th Annual Logging Symposium held in Abu Dhabi, United Arab Emirates, May 18-22, ABSTRACT Knowledge of formation fluid viscosity and its vertical and lateral variations are important for reservoir management and determining field commerciality. Productivity and fluid displacement efficiency are directly related to fluid mobility, which, in turn, is greatly influenced by fluid viscosity. Therefore, viscosity is a critical parameter for estimating the economic value of a hydrocarbon reservoir and also for analyzing compositional gradients and vertical and horizontal reservoir connectivity. The conventional methods for obtaining formation fluid viscosity are laboratory analysis at surface and pressure/volume/temperature (PVT) correlations. However, deducing viscosity from correlations introduces uncertainties owing to the inherent assumptions. Surface viscosity measurement may be affected by irreversible alteration of the sampled fluid through pressure and temperature changes, as well as related effects of long-term sample storage. A new downhole sensor for a wireline formation tester tool has been introduced to measure the viscosity of hydrocarbons. The new viscosity sensor uses a vibrating-wire (VW) measurement method with wellestablished analytical equations for interpretation. Downhole field testing of an experimental prototype has been conducted, with extensive laboratory tests to validate the sensor performance in viscosities ranging from light to heavy oil and at a wide range of well environments. The vibrating wire viscometer sensor meets requirements not only for measurement performance, but also for operations in downhole applications, and possesses the following properties: High-pressure and high-temperature qualification (25,000 psi and 347 F) Fast response time with an accurate viscosity measurement provided every second Installation in standard downhole fluid analyzer modules in wireline formation testers, made possible by recent miniaturization Deployment in sections with immiscible contamination Accurate temperature measurement of flowing fluid In addition to overall results for field tests, field examples of viscosity measurements are presented from a deepwater Gulf of Mexico well. In-situ measurements were performed by flowing noncontaminated reservoir oil using the focused sampling technique. The measurement of bottomhole flowing pressure and temperature, and other fluid properties such as density and gas/oil ratio (GOR), together with viscosity, allowed comprehensive analysis of the integrated dataset to understand the reservoir. INTRODUCTION The importance of viscosity for oil production, completion design and overall reservoir management is very well understood. Viscosity not only controls productivity and displacement efficiency of the reservoir, but plays a major role when designing subsea hardware and pipelines and for managing flow assurance related concerns. Accurate and timely viscosity data is of significant importance for the optimization of the production phase of every well. A new miniaturized vibrating wire sensor has been developed to measure the viscosity of live hydrocarbons, from a range of 0.2 to 300 cp, under flowing conditions, in a reasonably clean environment (Khalil et al., 2008; Godefroy et al., 2010a, 2010b; Daungkaew et al., 2012). The vibrating wire sensor consists of a thin metal wire held taut at both ends in a sensor body (Fig. 1). The vibrating wire excitation and the detection of its motion can be performed with either steady state or transient 1

2 methods. Fluid Flow F Lateral view B i measurements of the transient method have been discussed in detail elsewhere and were used without modification (Retsina et al. 1986, 1987; Assael et al., 1991; Sullivan et al., 2009). The emf ring-down signal consists of an exponentially damped sinusoidal ring-down (similar to that of damped simple harmonic motion) such that the induced emf voltage V(t) is given by Top view Fig. 1 The vibrating wire (orange) is held taut by two supports (poles) inside the flowline (black) of the formation evaluation tester. Current (i) is passed through the wire in the presence of a magnetic field (B) resulting in an orthogonal force (F) as given by the right-hand rule. The lateral view is restricted to the vibrating wire in the flow line; the top view includes the wire and external magnets in the circular geometry of the sensor (see Fig. 4). t V( t) V0e sin( t )... (1) where V 0 is the initial amplitude of the transient, the decrement linked to the damping experienced by the wire, the angular resonant frequency, and the phase angle. This emf is created by the temporally changing magnetic flux in a loop consisting of the wire as dictated by Faraday s law. In Equation 1, the decrement is related to several properties, including fluid density, but dominated by the fluid viscosity, enabling the device to function as a viscometer. Two examples are presented below (Fig. 2 and Fig. 3) that demonstrate how the ring-down varies with viscosity. In each case, the characteristic time of the ring-down [1/( )] is shown to be on the order of milliseconds, providing a rapid measurement when implemented downhole. To calculate viscosity, the vibrating wire sensor uses fluid density as an input, which is provided by downhole density sensor (vibrating rod or DV rod). In turn, the vibrating rod can measure both fluid density and viscosity under ideal conditions, but experience has taught us that the installation of both sensors in the toolstring allows for the most reliable measurement of viscosity, even in difficult fluid conditions. The steady-state approach to measure fluid viscosity excites the wire with an oscillatory current at each frequency and simultaneously measures the resulting voltage (curiously referred to by the misnomer electromotive force, and more succinctly as emf) that is produced by the motion of the wire when subjected to a magnetic field. In contrast, the transient method briefly excites the wire at its resonant frequency, and, after extinction of the excitation, measures the resulting ring-down voltage as the wire loses amplitude. The latter method is used here because of its rapid measurement time as compared to the former. In both methods, the wire experiences a strong magnetic field (here, approximately 0.5 Tesla) perpendicular to its axis, thereby providing a Lorentz force which drives the transverse oscillation of the wire. The working equations used to determine the viscosity from 2 Fig. 2 After an electromagnetic excitation, similar to the plucking of a guitar string, a long-lived ring-down voltage is observed in a fluid of viscosity 4 cp where

3 the frequency is measured to be 1957 Hz and the time constant 5.4 ms [1/( )]. The voltage is generated by the oscillatory motion of the wire as dictated by Faraday s law. Fig. 4 The vibrating wire sensor with integrated electronics is small enough to fit in the palm of the hand. Fig. 3 In contrast to Fig. 2, a short-lived ring-down (1.0 ms) is created in a high-viscosity fluid (104 cp). The frequency here is 1851 Hz. For both this graph and that in Fig. 2, agreement between data and model is to the point that the two curves cannot be distinguished. One benefit of this design is its insensitivity to flow. Documented benchmarking confirms that high flow rates with viscous fluids parallel to the wire do not detrimentally bias the measurement (Harrison et al., 2007). The miniature vibrating wire sensor shown in Fig. 4 and Fig. 5 is qualified up to 347 F and 25,000 psi. The sensor also includes a platinum resistance-temperature detector thermometer. Altogether, including electronics, the sensor body is 5 cm in diameter which allows it to be installed in the downhole fluid analyzer of wireline formation tester tool. This location enables the measurement of the viscosity in close proximity to other in-situ measurements, such as fluid density, gas/oil ratio (GOR), and fluid composition, together with pressure and temperature of the flowline. 3 Fig. 5 VW sensor resting on tool, about to be installed in the third sensor slot (also known as coffee-cup slots) of the wireline formation evaluation tool that performs downhole fluid analysis. The first slot is used for the resistivity cell and the second slot for the DV-rod sensor. The vibrating wire body and the wire material are made of alloys, with the latter having oleophilic properties, enabling the sensor to measure the formation oil viscosity even in the presence of water. During laboratory measurements and field tests, it had been determined that a high water fraction in the flowline adds noise to the measurements. Fig. 6 presents the results of the experiments with two different oils under a nominal flow of 10 cm 3 /s: a hydraulic oil referred to as Univis J13 and the pure hydrocarbon n-dodecane, each possessing significantly disparate viscosities. For the experiments with J13, the sensor continued to read with accuracy better than 10% for water fractions up to 10%, but when the water fraction was increased to 30%, the standard deviation of the readings increased significantly, although the average value remained the

4 same. This experiment was confirmed with lighter oil, n-dodecane, with a viscosity of 1.36 cp. In this case, the measurement was still within the specifications at 10% water fraction, although it was very noisy. At 40%, it was visually confirmed that the dodecane was emulsified with water and the effective fluid viscosity was considered to be altered. Flow with clean fluid Flow rate varied between 15 to 8 cc/sec Flow with fluid with sand particles 15 cm 3 /s 8 cm 3 /s Fig. 6 Oil viscosity measurement in laboratory with controlled water fraction with oils of two different viscosities. The round marker indicates median values of the readings. The sensor behavior was also tested to determine its performance in particulate-laden fluid flow (sand), which occurs when testing unconsolidated reservoirs. Fig. 7 shows the laboratory results. Results are first presented (upper graph) from the vibrating wire viscosity measurements of a particulate-free fluid where the flow rate was varied from 8 to 15 cm 3 /s. In this case, all the measured points are within the specified uncertainty. When sand particles were added (up to 100 g/l, see lower graph), the error greatly increased at a flow rate of 15 cm 3 /s, but reduction of the flow rate to 8 cm 3 /s significantly lowered the error, and the measurement error fell within the specifications. Therefore, during the field jobs, if the sensor was providing data with a large degree of scatter, it could be an indication of flowing sand, which can be reduced by lowering the flow rate. The sensor design has been qualified for flow rates up to 66 cm 3 /s (Godefroy et al., 2010b). Fig. 7 Experimental result on the effect of sand in viscosity measurement. The vibrating wire uses a permanent magnet that has the potential to attract metallic debris and particles that might be present in the flowline. The effect of magnetic particles will be observed as a drift on the measurement due to their physical interaction with the vibrating wire sensor probe, thereby affecting the ring-down decay and hence the viscosity measurement. To avoid this, it is recommended to avoid circulating mud through the wireline formation tester and to flush it before doing a downhole job. Additional precautions are also taken to minimize magnetic debris in the vibrating wire sensor, including the installation of a magnet in the formation evaluation tool flowline upstream of the sensor and the installation of a ditch magnet at the rig. During the field test campaign, a total of 34 jobs were conducted in wells drilled with oil-base mud with temperatures ranging from 40 to 150 C and pressures from 2,300 to 25,000 psi (Fig. 8). 4

5 electromagnetic viscometer (EMV) were compared to the vibrating wire sensor measurements from the field (log), as shown in Table 1. The comparison showed good agreement, and the detailed results are presented later in this paper. Table 1: Laboratory and Downhole Viscosity (using mini vibrating wire) Measurements Laboratory Viscosity (EMV) In-situ Viscosity (Log) Sample cP 160 ºF, 5,965 psi 0.68 cp 146 ºF, 5,860 psi Sample cp 176 ºF,6,875 psi 0.78 cp 175 ºF, 6,745 psi Fig. 8 Plot of pressure versus temperature during field test jobs. During field tests, a total of 43 hydrocarbon stations were performed with vibrating wire sensor providing good results, in this way adding value to the other insitu measurements present in the formation evaluation tester and providing a complete map of data to facilitate improved well evaluation. In certain cases, vibrating wire viscosity results were complemented by vibrating rod density and viscosity measurements. Having two sensors in the formation tester tool provides in-situ viscosity via two different sensing techniques; accurate measurement by the vibrating wire sensor was achieved in 95% of the cases. Both cases will be reviewed in detail in the field examples described below. FIELD EXAMPLES Sampling and downhole fluid analysis (DFA), including viscosity measurements, were performed in two wells in a field in the deepwater environment of Gulf of Mexico wherein the objective of both wells was to properly evaluate the reservoir and to establish important fluid characterization parameters and connectivity. In well 1, fluid sampling and DFA were performed at six depths (four oil, one gas and one water station). In well 2, fluid sampling and DFA were performed at six oil stations and two water stations, acquiring a total of 11 pressure/volume/temperature (PVT) sample bottles and two 1-gal chambers. Four of the test stations were primarily for fluid characterization and compositional gradient determination. After the wireline job detailed laboratory analysis was performed on two of the oil samples, and the laboratory viscosity results from an 5 Though laboratory viscosity measurements were performed for only two sample depths, downhole viscosity was available for all of the 11 hydrocarbon sampling and DFA stations. As the results of the field test were positive, the viscosity data from the wireline formation tester (WFT) for all stations were used in reservoir evaluation to better understand the petroleum system. DFA was exclusively performed on clean fluid in the flowline and the samples acquired subsequently confirmed contamination levels less than 5%. DFA results for all stations across both wells are presented in Table 2. Laboratory measured fluid properties results are available for three stations which are noted for comparison with DFA data. The DFA stations listed in the table are also the sampling stations. The DFA station numbers will be referenced to this table in subsequent plots. Even though the laboratory analyses of only three stations are shown in detail, the contamination level for the other stations as reported by the laboratory was approximately 3% or less. Fig. 9a consists of a station plot (Well 2, DFA Station #3) which includes viscosity, density, GOR, and fluid composition. Pumpout data is also provided to understand changes in flow rates. The horizontal axis indicates the elapsed time in minutes. In this job, the DFA tool was placed upstream, which means between the sampling inlet device and the pump module. The viscosity data (red) show a relaxation curve, which corresponds to the cleanup process of the drilling-mud by formation oil and which agrees with the other downhole measurement data, such as GOR (green), vibrating rod density (purple), and composition analysis (middle plot). Flowing fluid fraction is shown at the bottom section of the plot with green indicating oil. From the log it is observed that the in-situ viscosity reading was very stable after the cleanup and provided an absolute viscosity value 0.68 cp at 146 F and 5,860

6 psi. During part of the pumping duration (45 to 58 minutes), intermittent fluctuation in viscosity was observed which was most likely due to solids flowing next to or accumulating on the sensor. The in-situ viscosity number is taken from the stabilized and usually lowest values of the measurement; experience teaches this to be the most accurate. Fig. 9b shows the tested interval described above, in more detail and including pressure and temperature. The temperature reading was taken from the vibrating wire sensor and was verified from pressure and temperature sensor in the WFT tool. Fig. 10a and 10b (Well 2, DFA Station 4) comprise another station plot consisting of flowing fluid type, insitu composition, GOR, fluid density, and viscosity, the latter two being from the vibrating rod and the vibrating wire. From the log it is observed that the in-situ viscosity reading was very stable after the cleanup and provided a viscosity value of 0.62 cp at F and 5,935psi. Viscosity measured from both of the sensors is in good agreement providing high confidence in downhole measurement. The temperature reading is taken from vibrating wire sensor, which is also verified from the pressure and temperature sensor in the DFA tool. The pressure value, specified above, is the flowline pressure measured by pressure gauge installed in the DFA tool itself. In Fig. 11, the results from DFA station 2 of well 1 are presented; the viscosities from both the vibrating wire and vibrating rod sensors are shown. Since the fluid cleanup started during the pumpout phase of the station, the viscosities from both sensors start to stabilize after about 25 min of pumping. After this time period, the vibrating rod viscosity starts drifting upwards, possibly due to some type of fluid or solid sticking at the sensor. Hence, only vibrating wire viscosity was used from this station. The presence of two viscosity sensors in the DFA tool simultaneously allows representative in-situ viscosity measurements to be taken even in the challenging flow conditions. Table 2: Measured Fluid Properties, DFA Tool and Laboratory (PVT LAB) DFA/ LAB Well 1 Depth (ft) GOR (ft3/bbl) C1 (wt%) C2 (wt%) C3-C5 (wt%) C6+ (wt%) DV-Rod Dens. (g/cm3) Insitu Viscosity (cp) Conta minati on (%) Fluore scence DFA 1 XX < Oil DFA 2 XX < Oil DFA 3 XX < Gas DFA 4 XX < Oil DFA 5 XX < Oil Fluid Type DFA 6 XX150 NA NA NA NA NA NA <5 NA Water Well 2 DFA 1 XX < Oil PVT LAB XX NA 3.8 Oil DFA 2 XX < Oil DFA 3 XX <5 0.5 Oil PVT LAB XX Oil DFA 4 XX < Oil DFA 5 XX < Oil PVT LAB XX Oil DFA 6 XX < Oil DFA 7 XX480 NA NA NA NA NA NA <5 NA Water DFA 8 XX150 NA NA NA NA NA NA <5 NA Water 6

7 Fig. 9a Well 2, DFA station 3, in-situ fluid analysis results including viscosity, density, GOR, and fluid composition. Pumpout data is shown on middle graph to understand pumping duration. In-situ viscosity measured by vibrating wire sensor (0.68 cp, red curve) at bottomhole flowing condition of pressure 5,860 psi and temperature 146 F is in close agreement with PVT laboratory measurement (0.60 cp, at a pressure of 5,965 psi and temperature 160 o F) Fig. 9b Well 2, DFA station 3, enlarged viscosity plot along with pressure and temperature variation. In-situ stabilized viscosity of 0.68 cp is at bottomhole flowing condition of pressure 5,860 psi and temperature 146 F. PVT laboratory viscosity measured at surface is corrected for reservoir condition, at a pressure of 5,965 psi and temperature 160 o F. 7

8 Fig. 10a Well 2, DFA station 4, in-situ fluid analysis results including viscosities from vibrating wire (red) and vibrating rod (black), vibrating rod density, GOR, and fluid composition. Pumpout data is also shown to understand pumping duration and impact on measurements. The two viscosities match closely providing confidence in the measurement. There is no noise affecting the measurement as observed from the smooth viscosity curves. Fig. 10b Well 2, DFA station 4, enlarged view of Fig. 10a; in-situ viscosity (red and black) and density (blue) plots along with pressure (blue, lower graph) and temperatures (black and red, lower graph). Pressure is measured from the downhole fluid analysis tool. Temperature measured from both vibrating wire (red) and vibrating rod (black) sensors are presented, and there is difference of approximately 3 F between the two. 8

9 Fig. 11 Well 1, DFA station 2, in-situ fluid analysis results including viscosity from vibrating wire and vibrating rod, density, GOR, fluid composition, and pumpout flow rate. As the fluid cleanup started with the pumpout, the insitu viscosity from both sensors (vibrating wire viscosity, red curve; vibrating rod viscosity, black curve) start stabilizing (duration 10 to 25 min). Afterwards, the vibrating rod viscosity starts drifting upwards, possibly due to some type of fluid or solid sticking on the sensor. Hence, only the vibrating wire viscosity was used from this station. The presence of two viscosity sensors in the DFA tool allows representative in-situ viscosity measurement in over 95% of the cases. The PVT laboratory viscosity measurement results were obtained with an EMV. As mentioned earlier, two samples from different depths were analyzed, each belonging to a different sand in the same well (Well 2). The laboratory tests, presented in Table 1, provided viscosity values of 0.60 cp for the first sample, whereas the vibrating wire sensor showed 0.68 cp at slightly different pressure and temperature conditions. The laboratory viscosity was measured at surface and correlated to estimated reservoir conditions. The downhole (DFA) viscosity was measured at in-situ flowing pressure and temperature conditions. For the second sample, the downhole vibrating wire sensor measured a viscosity of 0.78 cp while the laboratory measurement was 0.72 cp. For both samples, the measurement agreed within the range of the specifications (±10%). Additionally, the sensor was able to see the slight difference of viscosity between the stations tested in the same reservoir, confirming the high precision of the vibrating wire sensor, which is specified as 3%. Fig. 12 is the composite plot of WFT measured pressures and mobility, downhole fluid properties, and basic logs such as gamma ray and induction array resistivity. Plotted over the upper reservoir section, the DFA data includes three oil stations and one water station as shown in the depth track. Optical density (OD), fluorescence, and viscosity show consistent compositional variation across the reservoir. Advanced equation of state (EOS) modeling was performed with an asphaltene size of 2 nm. A very close match of EOS predicted curve with measured OD confirms that the fluid is in equilibrium and most likely connected. (Mishra et al. 2012; Mullins et al., 2012). Reservoir connectivity conclusion is also supported by other petrophysical logs and geological information. Fig. 13 is the composite plot produced by the WFT across the lower sands in well 2 and includes pressures, mobilities, downhole fluid properties, and basic logs such as gamma ray, induction array resistivity, and imaging log. The DFA/sampling stations can be seen from the fluid composition plotted as horizontal bars in depth track. DFA measurements indicate that the top two stations consist of oil, the next deepest station consists of 9

10 water, and the bottom zone consists of oil. The DFA measurements- especially optical density, viscosity, and fluorescence -confirm that the bottommost sand has much higher viscosity and darker color than the middle sands. The presence of water zone confirms a barrier, supporting the DFA measurements. Imaging log and Gamma ray log indicate that the reservoir above water zone, across two oil stations, is heterogeneous with high degree of shaliness. While the insitu measured viscosity and density show standard variations in properties, the color indicates low degree of reversal with higher OD at top. This could possibly be due to localized accumulation of asphaltene over shale beds/baffles. Such examples emphasize the benefits of the integration of multiple fluid properties measurement downhole. Array Induction Resistivity 0.2 Mobility 2000 md/cp Insitu Density g/cc Insitu Viscosity cp GOR_IFA, ft3/bbl Asphaltene EOS predicted curve Measured Optical Density (OD) IFA Fluorescence Fig. 12 Well 2, composite DFA plot across upper reservoir. Depth track contains tested DFA/sampling interval with the fluid composition plots. The top three stations indicate flowing oil and the bottom most (blue bar) indicates flowing water. Viscosity and density are plotted in the fourth track from the left (green circle and red squares, respectively). Second track from right consists of the GOR (green) along with fluid optical density (red circles). The blue curve is computed from asphaltene equation of state modeling using 2 nm asphaltene sizes. The three measured OD stations falling on EOS curve confirms the fluid is in equilibrium and the tested zones are most likely connected. As it could be noted insitu viscosity and fluorescence measurements are also in agreement with the asphaltene gradient. Density and GOR variations are very small. 10

11 Fig. 13 Well 2, Composite DFA plot across lower reservoir. DFA measurements indicate that the top two stations consist of oil, the next station consists of water, and that the bottom zone is oil. The DFA measurements - especially optical density, viscosity, and fluorescence - confirm that the bottom most sand has much higher viscosity and darker color than the upper sands. Presence of water zone confirms a barrier supporting DFA measurements. CONCLUSIONS Fluid viscosity is one of the critical input parameters in reservoir evaluation, with expected large variation for compositionally graded reservoirs. However, it has been one of the most difficult measurements to achieve without an unacceptably high level of uncertainty. A new proven and robust DFA sensor, the vibrating wire sensor, provides higher reliability to the in-situ fluid viscosity measurement partially covered by the vibrating rod, as each sensor operates with different fluid mechanics with designs that could be affected in different ways in challenging downhole environments. Measurement of in-situ viscosity allows operators to perform economic evaluation of reservoirs with more data to support their conclusions, as there is no constraint in the number of stations analyzed. Furthermore, no additional logging time is required to measure viscosity since pumpout times were determined only by the amount of cleanup. The miniaturization of the sensor allows it to be conveniently installed in a slot in a WFT tool, eliminating the need for an additional module in the toolstring. Measurements with the vibrating wire sensor were performed in two wells in the deepwater Gulf of Mexico in a light oil reservoir with a range of 29 to 30 API. The result show the applicability of the insitu viscosity measurements, integrated with other DFA measurements and petrophysical and geological logs, for reservoir connectivity, compositional grading, and other major field decisions. These measurements also provide valuable results for realtime decisions such as acquiring clean fluid samples, optimizing the sampling and DFA stations, and performing reservoir fluid characterization. ACKNOWLEDGMENT The co-authors thank Schlumberger management for approval for presenting this paper. We also thank Murphy Oil and partners for approval for the publication of field examples. We thank Sophie Godefroy and Matthew Sullivan for useful conversations. 11

12 REFERENCES Al-Ajmi, M et al., Introducing the Vibrating Wire Viscometer for Wireline Formation Testing: In-Situ Viscosity. SPE Assael, M. J., Papadaki, M., Richardson, S. M., and Wakeham, W. A. 1991, An absolute vibrating-wire viscometer for liquids at high pressures: International Journal of Thermophysics, 21, Daungkaew S., Fujisawa, G., Chokthanyawat, S. et al., 2012, Is there a better way to determine the viscosity in waxy crudes?: SPE Asia Pacific Oil and Gas Conference and Exhibition, paper SPE Godefroy, S., O Keefe, M., Goodwin, A. R. H. et al., 2010, In-situ viscosity measurements from vibrating wire sensor developed for wireline formation testing: SPWLA 51st Annual Logging Symposium, paper Harrison, C., Sullivan, M., Godefroy, S. et al., 2007, Operation of a vibrating wire viscometer at viscosities greater than 0.2 Pa s : Results for a certified reference fluid with nominal viscosity at T = 273 K and p = 0.1 MPa of Pa s while stagnant and a fluid of nominal viscosity of Pa s while flowing: Journal of Chemical and Engineering Data, 52, Khalil, M., Rumhi, H., Randrianavony, M. et. al., 2008, Downhole fluid characterization integrating insitu density and viscosity measurements Field test from an Oman sandstone formation: Abu Dhabi International Petroleum Exhibition and Conference, paper SPE Mishra, V. K., Skinner, C., MacDonald, D. et al., 2012, Downhole fluid analysis and asphaltene nanoscience coupled with vertical interference testing for risk reduction in black oil production: SPE Annual Technical Conference and Exhibition, paper SPE Mullins, O., Sabbah, H., Eyssautier, J. et al. 2012, Advances in asphaltene science and the Yen Mullins model: Energy & Fuels, 26, Retsina, T., Richardson, S. M., and Wakeham, W. A., 1987, The theory of a vibrating-rod viscometer: Applied Scientific Research, 43, Sullivan, M., Harrison, C., Goodin, A. R. H. et al., 2009, On the nonlinear interpretation of a vibrating wire viscometer operated at large amplitude: Fluid Phase Equilibria, 276, ABOUT THE AUTHORS Vinay K. Mishra is Principal reservoir engineer and domain champion with Schlumberger, Houston, TX. He provides reservoir engineering support primarily formation testing sampling and DFA for Gulf of Mexico and Atlantic Canada operations. Previously he has worked in different roles of petroleum engineering based in Canada, Libya, Egypt and India. He has co-authored over 25 publications in international conferences including SPWLA and SPE. He has done B.S. in Petroleum Engineering from Indian School of Mines, Dhanbad, India. Vinay has been committee member and session chairs in several of SPE events. He is also registered with Association of Professional Engineers and Geoscientists of Alberta (APEGA) Beatriz E. Barbosa is the Reservoir Pressure & Sampling Product Champion with Schlumberger, Wireline HQ. Her responsibilities are the alignment of the domain road map with the industry needs and development of the required technologies. Previously she had several managerial positions as Wireline Geomarket manager (Peru, Colombia and Ecuador), Middle East & Asia Wireline Training Center Manager and Country Wireline operations manager. As a wireline field engineer and sales representative Beatriz worked in Angola, Colombia and Ecuador. She holds a degree in Civil Engineering from Los Andes University in Bogota Colombia (2001). Retsina, T., Richardson, S. M., and Wakeham, W. A., 1986, The theory of a vibrating-rod viscometer: Applied Scientific Research, 43,

13 Brian LeCompte is a Sr. Petrophysicist with Murphy Oil where he provides petrophysical support for the Gulf of Mexico and Atlantic Margins regions. This includes all aspects of rock, fluid, and pressure analysis for live well operations, new ventures, development, and exploration well planning. Brian previously worked with Baker Hughes in their research and development group from in the areas of mineralogy and shale evaluation. Brian has a M. Eng. in Petroleum Engineering from Texas A&M University and a B.A. in philosophy and mathematics from the University of St. Thomas in Houston, TX. He holds 3 US Patents and has published numerous papers with SPE and SPWLA. Yoko Morikami is senior physics engineer working on downhole fluid analysis sensors at Schlumberger K.K. She graduated from Osaka University, Japan, with M.S. in physics. Christopher Harrison is currently a program manager at Schlumberger-Doll Research in Cambridge, MA where he has worked for the past 10 years. He has focused on the development of miniaturized sensors to measure fluid properties, such as viscosity, density, and saturation pressure. He holds a doctorate in physics from Princeton University. Kasumi Fujii is a project manager in fluid analysis and sensors group at Schlumberger K.K. She graduated from Ochanomizu Univ., Japan with M.S. in physics. Dr. Cosan Ayan is a Reservoir Engineering Advisor for Schlumberger Oilfield Services, based in Paris, France. Currently he is the Wireline Headquarters Reservoir Engineering & Management Technical Director. Dr. Ayan leads Schlumberger Wireline Reservoir Engineering team worldwide and had similar headquarters positions for Petro-technical Services and Testing Services. During his twenty four years with Schlumberger, he held Reservoir Engineering positions in Dubai, Cairo, Abu Dhabi, Aberdeen, Houston, Jakarta and Paris. He works on interpretation and development projects, focusing on 13 wireline formation testers, transient well tests, production logging, and reservoir monitoring and reservoir management. Dr. Ayan holds BS degree from Middle East Technical University-Ankara (1981), MS (1985) and Ph.D. (1988) degrees from Texas A&M University- College Station all in Petroleum Engineering. He is the author of more than 60 technical papers on transient testing, reservoir monitoring and reservoir engineering and has several patents on interpretation, downhole tools and acquisition techniques. He has been on several technical committees for SPE, served as a SPE Distinguished Lecturer during and as Executive Editor-for SPE Reservoir Evaluation & Engineering Journal, Li Chen is a senior reservoir engineer and associate reservoir domain champion with Schlumberger, Houston, Texas, USA. He has the M.S. in Reservoir Engineering from China Petroleum University. His previous positions covered formation testing interpretation and answer product analyst in China. Hadrien Dumont is a Reservoir Domain Champion with Schlumberger, based in Houston. Previous positions held in Schlumberger include Field Engineer in Norway, Kazakhstan and Malaysia and Reservoir Domain Champion in Egypt, Sudan, Syria, Indonesia and United States of America. David Fernando Diaz works with Schlumberger supporting deep water Gulf of Mexico customers. He holds a degree in Electronics (1995) and a Master of Business Administration (2001). He started his career as Wireline field engineer in 1996, and since then held multiple positions in operations, support and management mainly for Schlumberger wireline formation evaluation services but also with the data and consulting services. Dr. Oliver C. Mullins is a Science Advisor to senior management in Schlumberger. He is the primary originator of Downhole Fluid Analysis (DFA) for formation evaluation. His current interests involve use of DFA

14 and asphaltenes science for reservoir evaluation. He has won several awards including the SPE Distinguished Membership Award and the SPWLA Distinguished Technical Achievement Award. He authored the book The Physics of Reservoir Fluids; Discovery through Downhole Fluid Analysis, which won two Awards of Excellence. Dr. Mullins also leads an active research group in petroleum science. He has co-edited 3 books and coauthored 9 chapters on asphaltenes. He has coauthored 210 publications with 3900 literature citations. He has coinvented 85 allowed US patents. He is Editor of Petrophysics, Fellow of two professional societies and is Adjunct Professor of Petroleum Engineering at Texas A&M University. His hobbies include skiing and biking. 14