composition in real time at downhole conditions, and of measuring the fluorescence ..... a condensate reservoir, this means that the liquid phase will accumulate in the pore space .... O.C.Mullins, A.Van Dusen, âOptimization of. Wireline Sample ...
SPE 87011 Exploration Applications of Downhole Measurement of Crude Oil Composition and Fluorescence Soraya S. Betancourt, Go Fujisawa, Oliver C. Mullins, Schlumberger-Doll Research, Kare Otto Eriksen, Statoil ASA, Chengli Dong, Julian Pop, Andrew Carnegie, Schlumberger Copyright 2003, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE Asia Pacific Conference on Integrated Modelling for Asset Management held in Kuala Lumpur, Malaysia, 29-30 March 2004. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836 U.S.A., fax 01-972-952-9435.
Abstract In addition to geological and petrophysical data acquisition during the exploration stage, in-situ fluid analysis provides a wealth of information for the appraisal of new discoveries. A recently introduced wireline sampling tool incorporating a downhole fluid analyzer is capable of analyzing fluid composition in real time at downhole conditions, and of measuring the fluorescence spectra of crude oils. These new measurements provide valuable information necessary for the identification and validation of reservoir structures that define the distribution of fluids in the accumulation. The relevance of high quality fluid data in the early stages of the producing life of the reservoir is widely recognized. We present field results of the application of the new sampling tool in an exploration well, where a composition gradient was detected along a 30m liquid hydrocarbon column grading from a 45API crude on the top to a 33API crude on the bottom. During the sampling of the gas cap, retrograde dew formation was detected identifying the fluid and identifying valid sampling conditions. This new information was used to modify the sampling program. Fluid composition analysis relies on optical absorption methods and is currently capable of providing the mass fraction of three hydrocarbon molecular groups: C1, C2-5 and C6+, and CO2. We perform fluorescence spectroscopy by measuring light emission in the green and red ranges of the spectrum after excitation with blue light. Fluorescence in this range is related to the concentration of polycyclic aromatic hydrocarbons (PAH’s) in the crude oil. Using the pump-out module to segregate different fluid phase enhances phase detection with fluorescence. Introduction Fluid properties relevant to reservoir evaluation are determined, for the most part, by laboratory analysis of
recovered samples, with the laboratory results being only as good as the samples provided. One main issue therefore for reservoir characterization is fluid sample validity/quality. Bottomhole samples are expected to be more representative of the original hydrocarbon since they are acquired and maintained at conditions similar to those in the reservoir. Valid sampling must satisfy two conditions: first, a minimum amount of contamination from foreign agents especially miscible mud filtrate should be present in the sample; and second, that sampling should be conducted under conditions guaranteeing that the fluid has not undergone any phase transitions; different phase have different mobilities yielding acquisition of nonrepresentative samples. Phase transitions may be induced by changes in pressure and/or temperature, the former being the most commonly encountered when sampling with wireline tools. Miscible contamination can also alter phase behavior. When the saturation pressure of the reservoir is unknown, as is mostly the case, the monitoring of fluid composition and fluorescence will indicate if the sampling pressure has fallen below the saturation pressure of the fluid. The sample will then be collected or not according to criteria based on the stability of the composition, and the minimization of filtrate contamination. To identify a retrograde condensate, one can steadily drop the sampling pressure below the saturation pressure of the fluid to observe the change in the fluorescence signal that will occurs with dew formation at the dew point pressure. This is a useful test for reservoir development since it identifies the existence of retrograde condensate, provides a real-time estimate of the fluid dew pressure, and gives information about the effects of two-phase flow on production performance. We can also monitor the estimated dew point against oil based mud (OBM) contamination. Another advantage of monitoring downhole fluid composition is that it enables us to assess oil-based mud (OBM) filtrate contamination level. The impact of OBM contamination is particularly severe for volatile hydrocarbons (condensates and volatile oils), where small concentrations of contamination can produce drastic changes in the nature of the fluid has been discussed previously. The monitoring of fluid color and methane concentration (or GOR) has been used successfully to calculate in real time the amount of contamination in the
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fluid.1-4 These studies have shown that downhole measurements of contamination agree very well with laboratory measurements. Moreover, it has been shown that the composition of the fluid and the GOR can also be corrected in real time for contamination and that the results are also in very good agreement with laboratory corrected compositions and GOR.2, 4 In this paper, we report the method to check if the hydrocarbon flow is in single-phase or multi-phase using changes in fluorescence signal and composition ratio. Further applying this idea, retrograde gas reservoir can be identified in real-time by intentionally causing a phase-segregation. We also report a large compositional gradient identified by the fluorescence signal in a field case study, this subject is further discussed in a separate paper.5 Physics of Measurement Molecules absorb light in a very specific way depending on their structure. They have quantized energy states or levels, and in passing from a lower energy state to another of greater energy they can absorb a photon whose energy is equal to the energy difference between the two states. In the UV-visible and Near-Infrared spectral ranges two molecular mechanisms dominate the absorption of light. The excitation of electrons, electronic absorption, in molecules generally occurs in the UV and visible. Nevertheless, in crude oils the large polycyclic aromatic hydrocarbons have electronic transitions in the nearinfrared. This spectral profile is characterized by an increasingly strong absorption at shorter wavelengths – without spectral peaks due to electronic overlap of many molecules (see Figure 1 top). The second mechanism, overtone and combination bands of molecular vibrations occur in the Near-infrared. These discrete absorption bands are characteristic of the particular chemical group absorbing photons, e.g. CH4, -CH3, -CH2- and the OH bond for water. Crude oils show variations in their absorption spectra in the visible and near-infrared region (VIS-NIR) according to their composition (Figure 1 bottom). The absorption within the range of wavelengths between 1600 and 1800nm is of particular interest because the CH2, CH3 and CH4 chemical functional groups found in petroleum exhibit the first CH stretch overtone (Figure 1 bottom). Water and CO2 have characteristic vibration peaks at different wavelengths that allow these compounds to be distinguished from hydrocarbons. In order to utilize UV-Visible and NearInfrared spectroscopy downhole, it is necessary to determine the impact of pressure and temperature on spectra. In a series of papers, it has been shown the effect of T and P on spectra is mostly through the influence on the fluid density.6-8 In another words, fluid spectra can be approximated as a function of density, not explicit functions of P and T. In addition, the relationship between the spectrum and the concentrations of the hydrocarbon species was established for mixtures of known composition using standard chemometric techniques.7,8 This procedure led to the development of the interpretation algorithm used in the downhole fluid analyzer to
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obtain the partial densities of the four chemical species (C1, C2-C5, C6+ and CO2).9 The details of this downhole fluid analyzer along with its field test results was described by Fujisawa et al9 for exploration and production environments. The fundamental principles of fluorescence spectroscopy are related to those for light absorption. After a molecule is excited by a photon, this energy can be released in the form of light after a discrete amount of time (in the order of nanoseconds).10 The molecules that are responsible for UVVisible fluorescence in crude oils are the polycyclic aromatic hydrocarbons (PAH). These molecules not only fluoresce, but are also responsible for the coloration of the fluid (light absorption is necessary for light emission).10 The fluorescence spectra for excitation at 470 nm of different hydrocarbons is shown in Figure 2.11 A downhole sampling tool attaches to the formation wall and extracts fluid by reducing pressure on the upstream side of a pump in the flowline. Compositional analysis of the flowline contents can be performed upstream or downstream of the pump or preferably in both locations in the sampling tool. The Composition Fluid Analyzer (CFA*) module contains a spectrograph with specifically designed wavelength channels that interrogate the fluid to extract composition in real time as the fluid flows through the line. The fluorescence spectrometer is in series with and close to the absorption spectrometer, so for practical purposes the two instruments are assaying the same fluid (Figure 3). The fluorescence spectrometer contains an LED (light emission diode) that excites the fluid with light in the blue region, and a set of detectors that receive the fluorescence light emitted in the green and red spectral ranges. The reflected light is also detected. The fluorescence detection unit (FDU) is designed to be sensitive to films of liquids enhancing the detection of retrograde dew formation. For condensates, when the retrograde dew phase forms, it exists first as mist surrounded by the continuous gas phase. This mist tends to create liquid films which to adhere to the walls of the flow line, and which show a contrast in fluorescence intensity with respect to the gas phase. Laboratory testing has shown that our fluorescence spectrometer unit is very sensitive to dew formation even with small amounts of liquid dropout. The fluorescence detection unit (FDU) has a sensitivity of 1% V/V and is useful for the early identification of fluid type and phase transitions in condensate systems. This new analysis tool is of invaluable use in the sampling program to understand the distribution of fluids within reservoir. First, in the acquisition of quality samples for PVT analysis (addressing important issues such as phase transitions, contamination, and sample quality control); and in the identification of fluid properties that impact the reservoir development plan such as the detection of CO2.
*
Mark of Schlumberger
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Identification of fluid composition gradients Variations in fluid composition with depth may occur for different reasons. Compositional grading can occur from a variety of sources including gravity, thermal gradients, biodegradation, leaky seals, real-time reservoir charging (without thermodynamic equilibrium being established), water washing etc. Because the physics of gradients cannot be know a priori, it is necessary to look for gradients during a sampling job and modify the sampling program during the job if gradients are suspected. For example, if two depths are checked during a sampling job and exhibit different fluids, then this apparent gradient needs to be confirmed by more testing in that same oil column. On the other hand if a zone is checked and shows the same fluid twice, then more sampling is not indicated. With the new downhole fluid analysis tool, a compositional gradient in a 30 m-liquid hydrocarbon column was detected in a North Sea exploratory well5. Variations in the fluorescence measurement with depth are shown in Figure 4, showing a strong correlation with the PVT laboratory-determined molar fraction of C10+. The fluorescence varies nonlinearly with GOR. The fluorescence depends on both optical absorption strength (color) and optical emission strength (quantum yield). This produces different sensitivities for the compositional analysis and the fluorescence measurements in identifying different fluids. Consequently, fluorescence and compositional analysis are complementary for identification of distinct hydrocarbon. It is a requirement to have downhole sampling in order to detect gradients. Without downhole analysis, possible differences measured in the laboratory in composition between different sampling points might be due to fluid variations or sampling difficulties. In the past delicate fluids have been validated by filling ~6 bottles with the same fluid. Blindly looking for gradients by going to, say, 5 sampling stations per column becomes prohibitive in the sampling bottle load. In addition, the inefficiency in sampling many different points all with the same fluid is unacceptable. Downhole sample analysis allows the sampling program to be quite efficient. The new sampling tool offers the versatility of assessing the existence of a composition gradient without the need of bringing samples to the surface. Normally the formation pressure profile is determined along the wellbore by means of a series of measurements, often called “pretests”, in which a small amount of fluid (10-20cc) is extracted at each station. The extraction of fluid causes a pressure disturbance in the reservoir, which, if the pretest is properly executed, asymptotically approaches the reservoir pressure at that station. For the most part the local pressure profile is a measure of the in-situ density of the uncontaminated formation fluid located at any particular depth and is therefore also a reflection of the fluid’s composition. However, the pressure gradients are well known to be grossly insufficient to find compositional gradients – only different phases can be identified. A similar multipoint concept could be adopted for the sampling tool, namely, by extending the time per station by a few minutes –beyond the time required to execute a
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pretest – to allow for pumping of fluid from the formation, at least until virgin formation fluid arrives at the tool, and the composition can be measured. In this way it should be possible to arrive at a fluid composition profile along the trajectory of the wellbore, which may be interpreted together with the pressure profile and an equation of state. We refer to this process as “downhole fluid analysis” and is distinct from sample acquisition. The previously described approach has the potential to be very informative for reservoir characterization, since variations in fluid composition that cannot be explained with the simple gradient models would correspond to a more complex fluid system or perhaps discontinuities in the hydrocarbon column due to the geological structure of the reservoir. Detection of Phase Transitions during Sampling One way in which downhole fluid samples are acquired is by placing a wireline conveyed tool in front of the zone of interest, extending a probe to make contact with the rock, and lowering the pressure inside the tool to withdraw fluids from the reservoir. The sampling pressure is measured close to the sandface, and if it is below the saturation pressure of the fluid a phase transition will occur. In a condensate reservoir, this means that the liquid phase will accumulate in the pore space until it exceeds the saturation at which it is able to move within the rock and into the tool. A main advantage of using a wireline sampling tool is that by controlling the sampling conditions – principally the sampling flow rate and thereby the sampling pressure – the sampled fluid may be kept close to its original condition of pressure and temperature. If the flow rate is required to be kept too low, the time needed to extract a certain amount of filtrate-free fluid will be long thereby increasing the risk of the tool sticking in the wellbore. A compromise usually has to be made between sampling time (flow rate) and pressure, with the primary consideration being given to the quality of the sample, i.e. no phase transitions. When a phase transition occurs in a retrograde condensate fluid, the newly formed liquid phase will concentrate the heaviest components of the original fluid. As was previously mentioned these heavy components contain the molecular groups that fluoresce. Fluorescence measurements are highly sensitive – even more so than other types of spectroscopy such as absorption spectroscopy – therefore making it possible to detect the slightest changes in the composition of the fluid being assayed. The detailed mechanical behavior of certain modules employed in wireline tools used to acquire fluid samples can be used to advantage for the interpretation of fluorescence. Fluids are drawn out of the reservoir by lowering the tool pressure below the formation pressure, and enter the tool usually through a probe. A traditional way to move the fluids inside the tool is with a reciprocating pumping unit consisting of two chambers that are alternatively filled and evacuated. Normal times of residence within one pump chamber are about 45 sec (filling up and transition) during which time gravitational segregation of fluids of different densities has
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been observed. If the fluorescence detection unit is placed downstream of the displacement unit the fluid segregation is advantageous in identifying the types of fluids being pumped. When the FDU is upstream of the displacement unit, the detection of liquid phases relies on the adherence of the liquid film to the fluorescence spectrometer window. We analyze simultaneously the absorption spectrum of the fluid and the fluorescence measurements. This enables us to detect changes in the fluid composition that can be correlated with the fluorescence signal, and is particularly advantageous when the fluid phases are separated. Consider fluid exiting the pump-out unit, variation in the ratio of mass fractions of light to heavy components, C1/C6+, indicates that the fluid composition is not constant, and may imply that different fluid phases are present in the tool. If fluorescence peaks when the C1/C6+ ratio is low, followed by decrease in fluorescence as C1/C6+ increases, then there is a liquid phase followed by a gas phase. Figure 5 depicts the gravitational segregation within the pumping chambers, and the signals that the separated fluids generate when passing by the optical sensors. The three phases inside the pump-out unit are water (blue), oil (green) and gas (red). Orange indicates the hydraulic oil used to move the piston. In the downstroke motion of the pump the fluorescence signal peaks after the water has been expelled from the pump, and we have indication of hydrocarbon. Both C1/C6+ ratio and fluorescence signal are changing during the hydrocarbon flow, and that indicates hydrocarbon flow is in two-phase; initially liquid as indicated by high fluorescence and low C1/C6+ ratio and later gas as indicated by low fluorescence and high C1/C6+ ratio. Gas downhole is still fairly dense due to high pressure. Fluid data is essential for reservoir evaluation and development, including well completion, facilities design and asset management. It is important to acquire high quality fluid samples at the exploration stage before the field is commissioned and put on production, and when fluids are closest to their original conditions. Since in exploratory wells the nature of the fluids is not fully known, precautions must be made to guarantee that the acquired samples are representative of the virgin in situ fluids. Quality samples imply the identification and rejection of samples that have undergone a phase transition, the need for contamination monitoring and minimization, and sample follow-up during the different stages of analysis. Contamination by Oil-Based Mud Filtrate One of the advantages of having a fluorescence spectrometer is that the presence of large concentrations of water precludes the measurement of hydrocarbon composition by means of optical absorption spectroscopy, whereas the fluorescence measurement is still sensitive to even small concentrations of fluorophores in the fluid. As was shown in Figure 2, the fluorescence spectra of hydrocarbons vary with composition. These variations are useful to identify different hydrocarbon types, and can assist in the monitoring of the cleanup of the miscible mud filtrate contamination during sampling, Oil-
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based drilling mud (OBM) and synthetic-based mud, (SBM) contain saturated hydrocarbons that do not fluoresce, although, in some cases, they contain additives such as surfactants that may exhibit high fluorescence intensity. Generally the surfactants do their designed function, stick to clays and invert emulsified water and do not get into the formation. In most cases the fluorescence of the filtrate will be different from the fluorescence of the formation fluid. As the filtrate fraction in the fluid decreases with pumping time, the fluorescence of the mixture will also change. These variations in fluorescence in formations drilled with OBM is particularly important for condensate fluids, where even small concentrations of contaminant alter the fluid PVT behavior. It is also important in condensate reservoirs drilled with OBM to be able to distinguish between the fluorescence due to filtrate and the fluorescence due to phase transitions. Many exploratory wells are drilled with OBM or SBM to reduce drilling risks. The base fluids of these types of drilling muds are hydrocarbons that are miscible with reservoir hydrocarbons, and therefore affect negatively the quality of the sample if contamination is high. The lighter the reservoir fluid, the more adverse are the effects of contamination. Under the valid assumption that mud filtrates are colorless, and do not contain methane, it is possible to monitor the cleanup of the fluid extracted from the reservoir as a function of time.1 The monitoring of color and methane content is related to the amount in volume percent of OBM filtrate in the fluid. When an acceptable value for the fraction of filtrate in the sample is reached, the operator makes the decision to capture a sample for fluid analysis. With downhole fluid analysis, one can analyze the valid fluid sample and adjust the sampling program according to this new input. Knowing the composition of the fluid and the amount of contamination it is also possible to calculate the composition and the GOR of the uncontaminated fluid. Experimental and Field Test Results Laboratory and field experiments were performed to measure fluorescence in fluids undergoing phase transitions. Laboratory results demonstrated the ability of the FDU to detect phase transitions in retrograde condensate systems. The tool was set to measure the composition of two condensate samples during a constant composition expansion of the fluid at reservoir temperature, starting at a pressure higher than reservoir pressure. Although these experiments were conducted in water-free environment and under quasi-static conditions, they are illustrative of the effects of phase transitions on fluorescence. Figure 6 shows one of the laboratory tests, where a North Sea retrograde condensate fluid initially in single (gas) phase is subject to a pressure expansion while optical absorption and fluorescence are measured. Notice that at time 6600 sec there is an expansion from 7000 psia to 6000 psia (red curve) where fluorescence peaks (green signal). At this time the phase transition has occurred and the formation of a liquid phase
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with a concentration of fluorophores causes this fluorescence response. The actual dew pressure of the fluid is 6200 psia. The North Sea field data shown in Figure 7A corresponds to a gas condensate system at near saturation conditions. The extraction of fluids at this station was performed by imposing a large pressure drawdown of about 25bar below formation pressure. This large drawdown was applied from the beginning and the fluorescence and composition variations were observed throughout the test indicating the presence of two phase flow. The fluid analyzer was placed downstream from the reciprocating pump, making it possible to take advantage of the segregation of fluids within the pump chambers as described previously (Figure 5). In the downstroke motion the green fluorescence response (FLD[0]) peaks after the water (WRHO) has been expelled from the pump, and we have an indication of hydrocarbons being present. The ratio of light to heavy hydrocarbon components (C1/C6+) is not constant during the time when fluorescence peaks which is further evidence that the fluid passing by the FDU contains mostly heavy components. Fluorescence dims while there is still hydrocarbon flow according to the composition log. Although at this time the signals are not conclusive of the existence of two-phase flow, ten minutes later (Figure 7B) when the hydrocarbon slugs are wider, the composition and fluorescence changes are more evident. All evidences indicate the hydrocarbon flow is in two-phase. Evidently, after the phase transition in the gas zone was detected, the sample was rendered unacceptable. A new sample was taken in the gas zone after repositioning the sampling tool to avoid the damaged zone near the wellbore where the liquid dropout accumulated. The comparison of the laboratory analysis of the new sample and the information collected during sampling was very informative. Laboratory results indicated that for the pressure drop imposed on the fluid, the liquid dropout volume fraction should be about 40% of the fluid. The difference in the composition measured with a high drawdown and a low drawdown gives a very useful indication of the recovery that may be expected from this zone. It is interesting to compare the fluorescence and composition behavior in the gas condensate zone with the adjacent oil zone (Figure 8) where the flow remained single phase. There is not a considerable variation in the C1/C6+ ratio, and fluorescence peaks are wide all along the period in which hydrocarbon is passing by the FDU. They are good indicators of the fluid being in single phase, necessary condition for fluid sampling. Conclusions Downhole fluorescence and composition measurements have been used successfully in exploration situations to obtain valuable information about the reservoirs. In an exploration well a compositional gradient within the hydrocarbon column was measured, and a phase transition was observed in the gas condensate zone. In single-phase flow the variations in composition and fluorescence occur in concert. When this is
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not the case, the fluid being assayed is not in single phase, i.e. a phase transition has occurred. For many condensates the phase transition is indicated by a sharp increase in the fluorescence amplitude of the fluid due to the larger concentration of fluorophores in the liquid phase, this may be used to obtain an estimate of the dew pressure of the fluid. Phase transitions can also be used advantageously to extract information about the fluid behavior within the reservoir by monitoring the changes in composition during a steady decrease of wellbore flowing pressure. Nomenclature CO2: partial density of carbon dioxide, g/cc C1: partial density of methane, g/cc C2-5: partial density of C2 to C5, g/cc C6+: partial density of the hexanes plus fraction, g/cc FLD[0]: integrated fluorescence intensity for green and longer wavelength FLD[1]: integrated fluorescence intensity for red and longer wavelength FLD[2]: intensity of reflected blue light WRHO: partial density of water, g/cc Acknowledgements The authors would like to express their gratitude to Statoil ASA, and Schlumberger for granting the permission to publish this paper. Unit Conversion bbl cp ft3 °F gal lb/ft3 lbm psi
× 1.589 873 × 1.000 000 × 2.831 685 (F – 32)/1.8 × 1.589 873 × 1.601 846 × 4.535 924 × 6.894 757
E-01 = m3 E-03 = Pa/s E-02 = m3 = °C E-01 = m3 E+01 = kg/m3 E-01 = kg E+00 = kPa
References 1. O.C.Mullins, J.Schroer, “Real-Time Determination of Filtrate Contamination During Openhole Wireline Sampling by Optical Spectroscopy”, SPE 63071 presented at the SPE Annual Technical Conference and Exhibition, Dallas, TX, October 2000. 2.
O.C.Mullins, G.Beck, M.Y.Cribbs, T.Terabayshi, K.Kegasawa, “Downhole determination of GOR on single phase fluids by optical spectroscopy”, SPWLA 42nd Annual Symposium, Houston, Texas, Paper M, (2001)
3.
F.H.Fadnes, J.Irvine-Fortescue, S.Williams, O.C.Mullins, A.Van Dusen, “Optimization of Wireline Sample Quality by Real-Time Analysis of Oil-Based Mud Contamination - Examples from North Sea Operations”, paper SPE 71736,
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presentation at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, LA, 2001. 4.
C.Dong, O.C.Mullins, P.S.Hegeman, R.Teague, A.Kurkjian, H.Elshahawi, “In Situ Contamination Monitoring and GOR Measurement of Formation Fluid Samples”, SPE 77899, presented at the SPE Asia Pacific Oil and Gas Conference, Melbourne October 2002.
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G.Fujisawa et al, “Large Hydrocarbon Compositional Gradient Revealed by In-Situ Optical Spectroscopy”, submitted for 2004 SPE ATCE.
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O.C.Mullins, T. Daigle, C.Crowell, H.Groenzin, N.B. Joshi, “Gas-Oil Ratio of Live Crude Oils Determined by Near-Infrared Spectroscopy”, Applied Spectros., 55, 197, (2001)
7.
M.A.van Agthoven, G.Fujisawa, P.Rabbito, O.C.Mullins, “Near-Infrared Spectral Analysis of Gas Mixtures”, Applied Spectroscopy 56, 593, (2002)
8.
G.Fujisawa, M.A.van Agthoven, F.Jenet, P.Rabbito, O.C.Mullins, “Near Infrared Compositional Analysis of Gas and Condensate Reservoir Fluids at Elevated Pressures and Temperatures”, Applied Spectroscopy, 56, 1615, 2002.
9.
G.Fujisawa et al., “Analyzing Reservoir Fluid Composition In-Situ in Real Time: Case Study in a Carbonate Reservoir”, SPE 84092, presented at the 2003 SPE ATCE, Denver, CO, October 2003.
10. O.C.Mullins, “Interrogation of aromatic Moieties in crude oils and asphaltenes by optical spectroscopy”, O.C.Mullins, E.Y.Sheu, Editors, Structures and Dynamics of Asphaltenes, Chapter II, Plenum Press, New York, 2001. 11. T.D.Downare, O.C.Mullins, “Visible and NearInfrared Fluorescence of Crude Oils”, Applied Spectroscopy, 49, 754 (1995).
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Figure 1 Absorption spectra of hydrocarbons. A: a wide spectrum from 400nm to 2200nm. Absorption below 1500nm is primarily due to color. B: the vibrational overtone of hydrocarbon molecules between 1600nm and 1800nm is used to resolve the composition of C1, C2-C5, and C6+.
λ ex = 470 nm
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RFT 05-04 Brunei Vixburg Escravos Acoustics North Sea BG 5 Sales UG 8 Tex 141
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Figure 2 Fluorescence spectra of different hydrocarbons listed from the lightest to the heaviest. Significant variation is observed in fluorescence intensities and spectra among different crude.
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Fluorescence Detector FL CH#1 >Green 550nm
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gas
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oil water hydraulic oil
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Figure 5 When the fluid analyzer is downstream of the sampler’s pump-out unit the analysis is related to the motion of the pump. Segregation of the phases can be observed in fluorescence and composition.
F luo re s c e nc e (wa ve le ngth > 680 nm )
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Figure 6 Laboratory measurements of fluorescence and composition using optical spectroscopy on a real condensate during a constant composition expansion. At around 6615 sec a retrograde dew was detected.
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Figures 7A (top) and 7B (bottom) CFA analysis in a gas condensate zone. Two hydrocarbon phases (and water phase) are present. FLD[0]
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Figure 8 Fluorescence, composition, and Pressure data during the sampling of a black oil zone. A single hydrocarbon phase is present.
