Downhole Optical Analysis of Formation Fluids

Transcription

1 Downhole Optical Analysis of Formation Fluids Rob Badry Calgary, Alberta, Canada Derrel Fincher Sugar Land, Texas Oliver Mullins Bob Schroeder Ridgefield, Connecticut, USA Tony Smits Fuchinobe, Japan In the past, wireline formation samplers have not been able to see the fluid they were sampling. Downhole optical analysis of fluid before sampling removes the blindfold to reveal oil, water or gas. The sample chamber needs to be opened only when the desired fluid is present. Bringing formation fluid samples to the surface for examination was a novel wireline advance when it was introduced in the early 1950s (right). Run in open hole or cased hole, the Formation Tester (FT) took a sample of formation fluid where analysis of earlier runs of resistivity and porosity logs showed promising zones. The FT consisted of a sealing packer and probe system that could be set against the formation. Once this was set and opened, formation fluid drained into a sample chamber. The entire sampling operation, from set to retract, was monitored using a pressure gauge. The sample chamber was closed only when pressure stopped increasing implying the chamber was full and at formation pressure. 1 For help in preparation of this article, thanks to Hifzi Ardic, Schlumberger Wireline & Testing, Montrouge, France and Robert Gabb, Schlumberger Wireline & Testing, Livingston, Scotland. MDT (Modular Formation Dynamics Tester), OFA (Optical Fluid Analyzer) and RFT (Repeat Formation Tester) are marks of Schlumberger. 1. Finklea EE: Use of Pressure Buildup Curves from the Formation Tester for the Evaluation of Permeability and Reservoir Pressure, The Technical Review 9, no. 3 (August 1958): January 1994 (FT) Formation Tester 1955 (RFT) Repeat Formation Tester 1975 Electric power Hydraulic power Probe Dual-probe Flow control OFA Optical Fluid Analyzer Multisample Sample Sample Pumpout (MDT) Modular Formation Dynamics Tester 1992 Dualpacker nevolution of wireline formation testers. The Formation Tester (FT) had a pressure gauge to monitor sampling into a single chamber. Pretest chambers introduced with the RFT Repeat Formation Tester tool allowed a check on seal integrity and gave an indication of permeability before sampling into one of two chambers. The introduction of the dualpacker, with the MDT Modular Formation Dynamics Tester tool, allows sampling when seal failure might be a problem. The pumpout is used along with the OFA Optical Fluid Analyzer to confirm the presence of desired formation fluid before one of several sample chambers is opened. 21

2 The FT s probe and packer could be set only once per trip in the hole. This created a couple of problems. If the formation has low permeability, the sample chamber could take hours to fill, delaying rig operations and increasing the risk of the tool becoming stuck. Sampling in low-permeability formations was therefore often aborted. But sampling also had to be aborted if the seal between packer and borehole wall failed, indicated by a sudden increase in sampling pressure to hydrostatic. The only remedy was to pull out of the hole, redress the tool and try again. The next generation of testers addressed these difficulties. The RFT Repeat Formation Tester tool, introduced in the second half of the 1970s, allowed an unlimited number of settings or pretests before sampling was attempted. Pretest chambers were used to indicate the permeability and to check for seal failures. During a pretest two small volume chambers opened producing pressure drawdowns. Knowing the amount of drawdown for each chamber gave two estimates of permeability. Once the pretest chambers were filled, formation permeability could also be calculated from the subsequent buildup to formation pressure. 2 Sudden increase to hydrostatic pressure during a pretest showed seal failure. Testing the formation first allowed sampling to be carried out in zones where seal failures did not occur and where permeabilities were high enough to allow one of two sample chambers to be filled in a reasonable amount of time. However, RFT samples suffered important limitations: the sample too often contained a large percentage of mud filtrate and the flowing pressure sometimes dropped below bubblepoint changing the sample characteristics. Even when the sample was formation fluid, it could have been water or gas and of no interest to the oil company. These drawbacks frequently led to expensive and timeconsuming operations, to say nothing of frustration caused by the absence of anticipated information or the presence of data later found to be useless. The latest generation formation tester, the MDT Modular Formation Dynamics Tester tool, overcomes these problems The MDT Tool In the MDT tool, unwanted fluid is expelled from the tool using the pumpout. During sampling, the engineer can monitor the resistivity and temperature of fluid in the flowline while pumping it directly into the borehole or into a dump chamber. When fluid quality is judged to be representative of the reservoir, the pump is stopped and pure formation fluid can be diverted to the sample chamber or, if a sample is not required often the case when formation water or gas is indicated another zone can be tested. To prevent gas from coming out of solution during sampling, pressure is maintained above bubblepoint using throttle valves in the sample chambers controlled by surface software. Maintaining pressure above bubblepoint reduces drawdown, which helps prevent crumbling in soft formations. Excessive drawdown can result in seal failure and hence mud contamination of a sample. Drawdown can also be limited by using a water cushion and choke with the multisample. Formations in which seal failures are likely highly laminated or otherwise heterogeneous formations or formations that have low permeability can be tested and sampled using the dual-packer. Instead of a probe and packer to provide a seal, two inflatable packers are used to isolate an interval of about 3 ft [1 m] of formation forming a mini drillstem test. The pumpout is used to inflate the packers and also to expel mud from between the packers before sampling. Are all the sampling problems solved? Not quite! Resistivity will show transitions only if there is a resistivity contrast between fluids. And, in the presence of more than one phase, the interpretation can be dominated by the continuous phase, making sampling decisions difficult. Also, keeping gas in solution by controlling flowing pressure is possible only if the bubblepoint pressure is known. If bubblepoint pressure is not known, sampling pressure may be too low and the sample could be spoiled by the presence of free gas. A more complete analysis of flowline fluid is therefore needed. Providing a solution for these particular problems is the recently introduced OFA Optical Fluid Analyzer of the MDT tool. As fluids flow through the MDT s flowline, real-time interpretation of the measurements indicates the proportions of oil and water, and gives a qualitative indication of free gas. 4 How the OFA works The flowline passes through two independent optical sensors (next page, top). In one cell, absorption spectroscopy is used to detect and analyze liquid, while in the other cell, a special type of optical reflection measurement detects gas. This allows wellsite personnel to decide whether to divert the flow into a sample chamber for retrieval, continue to expel it into the borehole or into a dump chamber, or to increase the sampling pressure above bubblepoint. It has also been used to verify that the formation contains only water or only gas and that a sample is not required. Thus, the sample chambers in the tool are kept available for desired fluids only. Even when oil-base mud is used, it is possible to track the transition from borehole mud, to filtrate, to connate oil as long as the two oils differ in color. After a decision has been made to switch from pumpout to sampling, the OFA continues to monitor the fluid in the flowline in particular to verify that production remains above bubblepoint. A field test in a vuggy carbonate formation, where conventional probe seals are difficult to obtain, used the OFA along with several other features of the MDT tool. 5 The inflatable dual-packer isolated the test interval, and the OFA indicated the fluid in the flowline throughout the test (next page, bottom). After a pretest to check permeability and seal integrity, 44,000 cm 3 [10 gallons] of fluid were pumped through the OFA using the pumpout. OFA analysis shows that the fluid changes from borehole mud to filtrate to oil as pumping proceeds. After about an hour, pumpout into the borehole above the packers was stopped and flowline fluid was diverted to the sample chamber for collection. The throttle valve at the chamber end of the flowline maintained pressure above the bubblepoint during sampling. 2. Stewart G and Wittmann M: Interpretation of the Pressure Response of the Repeat Formation Tester, paper SPE 8362, presented at the 54th SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, USA, September 23-26, Colley N, Hastings A, Ireland T, Joseph J, Reignier P, Richardson S, Traboulay I and Zimmerman T: The MDT Tool: A Wireline Testing Breakthrough, field Review 4, no. 2 (April 1992): Badry R, Head E, Morris C and Traboulay I: New Wireline Formation Tester Techniques and Applications, Transactions of the 34th SPWLA Annual Logging Symposium, Calgary, Alberta, Canada, June 13-16, 1993, paper ZZ. 4. Smits AR, Fincher DV, Nishida K, Mullins OC, Schroeder RJ and Yamate T: In-Situ Optical Fluid Analysis as an Aid to Wireline Formation Sampling, paper SPE 26496, presented at the 68th SPE Annual Technical Conference and Exhibition, Houston, Texas, USA, October 3-6, Badry R et al, reference 3. field Review

3 Light-emitting diode Gas detector Lamp nthe OFA with its two sensor systems, one for liquid detection and analysis, and the other for gas detection. Fluid flow Liquid detector Time (sec) Pumpout Module Pumpout Volume cm 3 Optical Fluid Analyzer Highly Absorbing Fluid Comments Set packer Packer pretest Start pumpout Pumping filtrate nofa log display during sampling using the dualpacker. Starting at the top of the display, a pretest confirms the seal, followed by pumpout of 44,000 cm 3 of fluid from the packerisolated interval. The OFA display second track from the right shows flowline fluid change from filtrate to oil. Flow is then diverted to a 1-gallon sample chamber with throttle control to maintain pressure above bubblepoint. Pumping 60% oil ,000 cm 3 Stop pumpout Start sample Throttling Seal sample January

4 Optical density Visible Condensate Diesel base mud filtrate Near infrared Crude A Crude B Wavelength, nm n and water spectra. As the wavelength of light increases from the visible to the near infrared, the optical density of water changes from zero transparent to a high absorbing peak at 1450 nanometers (nm) and an even higher peak at 2000 nm. The spectra of various oils are also shown, some less optically dense (more transparent) than others in the visible region. A distinctive absorption peak for all hydrocarbons appears at 1700 nm. These peaks are used to distinguish oil from water. resistant to abrasion than quartz. Either path can be connected to a spectral distributor where the light is separated into wavelengths the intensity of each is measured. The wavelengths are chosen to optimize the determination of both the water/hydrocarbon ratio and the color of the fluid in the flowline (below). Spectral transmission measurements also permit a quantitative holdup analysis in oilwater systems. 7 But complications arise when gas is present. Scattering from the interface between liquid and gas, such as by a bubble, attenuates the transmission beam. First, this can add a roughly constant offset to the optical density curves. Second, the presents of gas reduces the height of the hydrocarbon peak, adversely affecting a quantitative holdup analysis. In fact, the hydrocarbon peak height is approximately linearly related to the gas concentration, but relying on this alone does not guarantee that gas is present. A second sensor is therefore used to detect gas and raise a warning flag. Differentiating Fluids Color the result of electronic absorption provides one more parameter for liq- The OFA distinguishes water from oil by differences in optical transmission of uid identification. Hydrocarbon condensates Lamp light at visible and near infrared wavelengths. The relative intensity of transmitted light transmittance, defined as the ratio of transmitted light energy to incident light appear clear or light reddish-yellow, while other crudes may be dark brown or black; undyed diesel and fuel oils tend to be light to dark brown. The color of oil is determined Measure path by the shorter wavelengths blue Source energy is measured at different wavelengths. Because transmittance of typical and green being absorbed while the path formation fluids may vary greatly versus longer wavelengths yellow and red are Sapphire wavelength, it is often convenient to represent optical properties on a logarithmic are absorbed by electrons in aromatics and allowed to pass. The shorter wavelengths windows scale and to use a quantity called optical asphaltenes in oil causing a change in their Formation fluids density. 6 The higher the optical density, the atomic energy state as the concentration less light is transmitted. A plot of optical of asphaltenes goes up, more light is density versus wavelength is called the absorbed. Analysis of color allows differentiation Flowline absorption spectrum (above). Three phenomena are primarily responsible for the between oil-base mud filtrate and crudes. Adding a dye to drilling mud could characteristics of these absorption spectra: be used to distinguish filtrate water from molecular vibration absorption, electronic connate water. Shutter absorption and scattering., as experienced in everyday life, absorbs very little light in the visible region. This continues at the shorter wavelengths in the near infrared region until a resonance in the molecular vibration of the oxygenhydrogen If particles mix with fluids as in drilling mud or if oil and water emulsify, then light will be scattered. This causes additional reduction in transmitted light. If the scattering contribution to optical density is large, the water and oil peaks may be obscured Spectral distributor Detectors nofa spectroscopy measurement system. Light from a tungsten halogen lamp is [O-H] bond causes a sudden and difficult to interpret. In this case, the directed along either of two paths. One path is used for downhole calibration, increase in absorption forming a peak near fluid is said to be highly absorbing and is while the other directs the light to the 1450 nanometers (nm). Another resonance usually interpreted as mud. flowline for measurement. Light passes in the O-H bond causes a second, much The transmission measurement is made through the flowline fluid via sapphire stronger, peak near 2000 nm. For oils, by directing light from a tungsten halogen windows to a light distributor where photodiode detectors, each tuned to a differ- molecular vibration absorption peaks at lamp to either of two paths. One path is ent wavelength, measure the transmission intensity. Liquid analysis is made 1700 nm, caused by a resonance vibration used for calibrating the sensor for minor system drifts before a measurement is taken. from these measurements. in the C-H bond. The uniqueness and separation of these peaks permit differentiation of oil and water. The other goes to the flowline, which is coupled to the light via small windows made of sapphire, sapphire being more 24 field Review

5 Detecting Gas Gas is detected by measuring reflected polarized light. 8 The amount of light reflected at a surface between two media depends on the media, the angle of incidence and whether the light is polarized. The reflection of all light, polarized or not, is governed by the critical angle. At angles of incidence greater than the critical angle, all light is reflected and none transmitted. At less than the critical angle, some light is reflected and some is transmitted. When light is P-polarized that is, polarized parallel to the plane of incidence there is a particular angle smaller than the critical angle, called the Brewster angle, that allows 100% transmission. Since values for the Brewster and critical angles differ significantly between gases and liquids, measuring the relative intensity of the reflected light over a range of angles permits positive identification of gas (right). Using both angles is desirable to detect gas in the presence of liquids. The reflection measurement is made using monochromatic infrared light emitted from a light-emitting diode (bottom, right). This is polarized and passed through a cylindrical lens, prism and sapphire window into the flowline. An array of six detectors measures the intensity of light reflected from the sapphire/fluid interface at discrete angles, from just below the Brewster angle for air, to just below the critical angle for water. Calibrations are carried out with air and then with water in the flowline. A gas flag is currently generated by a simple algorithm that uses the shape and location of the measured reflectivity curve between the 100-percentair and 100-percent-water curves. Reflection responds to the interface between two materials, in contrast to transmission spectroscopy, which samples the bulk material. Hence, the gas detector responds to free gas at the surface of the sapphire window, which may not necessarily represent the Relative reflection intensity, % Approximate band covered by detector array Angle of incidence Less than critical angle Lens and polarizer Critical angle Air Sapphire prism Brewster angle Detector array nrelative reflection intensity of P-polarized light for air, water and a typical oil. The relative reflection intensity is shown for varying angles of incidence for air, water and oil. The reflection intensity decreases to zero for P-polarized light at an angle of incidence called the Brewster angle. As the angle of incidence is increased, the reflection intensity increases until total internal reflection occurs at the critical angle. Brewster angles and critical angles are different for air, water and oil. Measuring reflection intensities over a range of angles provides the basis for the gas detection sensor. 6. Optical density is defined as the logarithm of one divided by transmittance. In other words, a transmittance of 100% is equal to an optical density of 0, a transmittance of 10% is equal to an optical density of 1 and so on. 7. cut is the percentage volume of water produced from a formation over a period of time. holdup is a snapshot of the percentage volume of water occupying a pipe or flowline under dynamic conditions. Because of different densities between flowing fluids, there is often a difference in flow velocity the water holds up the oil. holdup will be greater than water cut if the difference in velocity of oil and water is greater than zero. If there is no difference in velocity, then water holdup and water cut will be the same. 8. Light is an electromagnetic wave that oscillates in a plane perpendicular to its direction of travel. Polarized light is light whose oscillations are confined to one plane only. January 1994 LED Flowline Formation fluids ngas detector optics. Light from a light-emitting diode (LED) is polarized and spread over a range of incident angles through a sapphire window at the flowline. An array of detectors measures the reflection intensity over angles from just below the Brewster angle for air to just below the critical angle for water. Comparing intensities with those obtained from master calibrations allows gas detection flags to be raised on the log. 25

6 volume fraction of gas present in the flow. However, liquid films on the sapphire window do not impede gas detection. Distinguishing between single phases of oil, water or gas in the flowline using the OFA is straightforward: the gas detector shows either gas or liquid, while the absorption spectroscopy peaks define the liquid. If the flow is two or three phase, a more complex analysis is required to quantify volume fractions. This is possible for liquid holdup as the absorption spectrometer measures optical densities across the flow. However, the gas detector measures light reflected at the liquid sapphire interface, which generally produces a larger signal for greater gas fractions, but may not be representative of gas holdup. At present, water holdup is calculated directly from the calibrated responses of the detectors tuned to the two water peaks relative to those tuned to wavelengths at which water has very little absorbance. Subtraction from unity then gives hydrocarbon holdup. In addition, the log presents an oil indicator by shading the separation between the output of the detector tuned to the oil peak and the output of the detector tuned to a wavelength between the oil peak and the nm water peak. The magnitude of the separation gives an approximate measure of the oil volume fraction in a gas-oil mixture. When combined with the hydrocarbon holdup estimate, this can yield a rough appraisal of oil holdup. Since scattering reduces light transmission, a shift from the baseline of the optical density curves shows the magnitude of scattering. Independently, the gas detector flag indicates the presence of gas. The recording also presents optical densities measured by each transmission detector. These are tracked in time, and give additional indications of changes in flowline fluid composition. For a more formal approach to future interpretation development, see Effective Flow Stream Model, (below). Examples of Sampling Using the OFA Module In a field test in a naturally fractured formation, the dual-packer was used to provide a good seal and the OFA was used to monitor the flowline fluid composition during a pretest and subsequent sampling operation. 9 A display of each channel from the OFA spectroscopy measurement system shows the optical density measurement recorded throughout (next page). Channels 1 to 6 sample the spectrum below the first water peak and respond to color. Channels 6 to 10 channel 6 is repeated are the water/oil channels and respond to changes in the region of high 9. Smits AR et al, reference 4. Effective Flow Stream Model Flow regime Flow direction Model Light ntransforming flowline contents to effective flow stream (EFS) model. The two-phase flow stream cross section (left) is grouped into different flow regimes and simplified (right) into a model consisting of a number of optical components in parallel and series with the light. The calculation of oil and water holdup and estimations of fluid coloration and light scattering involves the solution of 10 one for each wavelength simultaneous equations given by this model. A somewhat more formal approach to interpreting complex flow regimes along the flowline through the OFA absorption sensor uses the Effective Flow Stream (EFS) model. It employs a set of transmission equations, one for each of the detectors. The unknowns correspond to oil and water holdups, degree of oil coloration and amount of scattering. The EFS model provides a method for reducing the dynamic flow to a static optical equivalent (above). The transition from flow stream to static model is made by grouping slug flow, emulsion or bubble flow, and layered flow, so as to segregate the transmissions accordingly. The EFS model reduces this to a simple partitioning of series and parallel transmissions. This model represents the measured transmission as just the time average of transmissions through oil, through water, and through oil and water in series. Scattering, such as occurs from particulates, emulsions and gasliquid interfaces, also contributes to attenuation by removing photons from the optical beam path. This is treated for both mixed and segregated phases as a wavelength-independent equivalent absorption in series with that of the flow components. The EFS model is also the basis for the ongoing development of additional, improved interpretation algorithms. 26 field Review

7 Time, sec SC 1 Valve Pos n Pumpout Motor Indicator Pumped Volume 0 cm 3 20,000 Pressure 0 psia 5000 Gas Highly Absorbing Fluid Fraction 1 0 Hydrocarbon Fraction 0 1 Optical Density Color Channels, Channels Comments Inflate packer Packer pretest Start pumpout Pumping filtrate Pumping oil Stop pumpout Start sample Throttling Change throttle nformation sampling with dualpacker and pumpout s. The top of the log (0 to 350 sec) shows the pumpout being used to inflate the packers of the dual-packer the OFA reading shows mud. During the packer pretest (400 to 750 sec) the OFA reading again shows mud. Fluid is then pumped out from between the packers changing from mud to filtrate (showing as water), and finally, at 2200 sec, to oil. Pumpout is stopped at 2550 sec and the sample chamber opened. During sampling, throttling controls the flowing pressure to ensure gas stays in solution. The 10 optical density channels are displayed to give a visual presentation of density changes throughout the test. Channels 1 to 6 sample the fluid spectrum below the water peak at 1450 nm and give an indication of changes in color. Channels 6 to 10 are the oil/water channels responding to changes above 1450 nm Seal sample January

8 absorption peaks. The character of the spectrum at any time can be visualized by sweeping the eye from left to right across the log and noting changes in optical density. Hydrocarbon and water holdup curves are shown in the adjacent track. In this example, the absence of a gas flag suggests that the hydrocarbon is all oil. Confirmation of this is visible on the oil indicator, which correlates well with the estimated hydrocarbon fraction and with optical density in the color channels. An initial flow of mud is visible on the optical density curves. These produce the highly absorbing fluid indicator that appears at the beginning of the log. The highly absorbing fluid flag appears whenever all of the detectors sense essentially no light. The OFA response to gas is shown in another field test where alternating slugs of water and gas occur (right). 10 The optical density track shows no absorption in the color channels, suggesting absence of oil, and increased density in channels that respond to the water absorption peaks. - and hydrocarbon-fraction curves step between 0 and 1 as slugs pass, and the gas flag responds similarly. The oil indicator confirms that the hydrocarbon is gas, and not a light oil that is transparent in the visible region no shading can be seen. The transmission differences between gas and water slugs cause oscillations in the optical density curves and, hence, the oil indicator curves and not because of changes in scattering. The very slight time shift between 10. Smits AR et al, reference 4. Time, sec Indicator Pressure 0 psia 5000 Gas nsection of log display during acquisition of a gas sample. The OFA spectroscopy measurement alternates between water and hydrocarbon. The color channels show transparent fluid, whereas the water/hydrocarbon channels oscillate. The gas detector shows oscillations between liquid and gas. The conclusion is that alternating slugs of gas and water are moving along the flowline. the optical density and gas-indicator curves results from the small flowline distance between the two sensors. Comparing measurements by the OFA with surface observations on the chamber contents must be done with care gas can come out of solution and liquids can vaporize. Preserving downhole temperature and pressure is necessary for valid comparisons since even returning them to their downhole values may not guarantee recombination of phases to their original condition. So far, OFA outputs have mostly been consistent with other knowledge about fluid production in individual wells. Several field tests have shown good agreement between OFA measurements and chamber analyses for oil and water, even Fraction 1 0 Hydrocarbon Fraction 0 1 Optical Density Color Channels, Channels though the OFA measures holdup and the chamber contents represent timeintegrated cuts. Other tests show quantitative disagreements that could be caused by several factors such as not flowing through the OFA during sampling or sampling at substantially different flow rates to those during pumpout. Further developments in OFA measurement and interpretation are in progress and new applications can be envisioned: aiding interpretation of drawdown pressure tests, providing new information on formation invasion and making quantitative estimates of bubblepoint under downhole conditions. JT, AM 28 field Review