New power in production logging

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1 New power in production logging Locating the zones where fluids enter the wellbore in a producing or injecting well is an important aspect of production logging. It is relatively straightforward to establish flow profiles in single-phase situations using conventional methods based on flow and density, but multiphase systems present a greater challenge to quantifying gas and liquid holdups. Conventional systems cannot detect small, liquid-entry points in gas wells, or distinguish condensate from gas. Chris Lenn explains how these limitations have been overcome by the * Gas Holdup Optical Sensor Tool, which uses the internal-reflecting properties of a system of optical sensors to detect and quantify very small amounts of gas in liquid or liquid in gas.

2 Production logging is vital for effective management of oil and gas assets. Reservoir engineers need detailed information about the types and rates of fluid flow in their reservoirs and wells. The main aim for production logging is to measure the performance of producing and injecting wells. This involves providing diagnostic information that can pinpoint where fluids enter the well, and indicate the efficiency of perforations. There are four fundamental production logging measurements flow, density, temperature and pressure. In traditional production logging, only the flow and density readings were used for quantitative analysis. Temperature and pressure data were normally used in a qualitative way to compute in-situ flow properties and to locate zones where fluids were entering or leaving the wellbore. In the past, analysis of production logging measurements focused on spinner (flowmeter) and density readings and results were very variable. In singlephase flow conditions, production-logging data are relatively easy to interpret and flow profiles can be assessed quickly. Flow profiles in multiphase systems are much more complex. Photodiode Light source Figure 1.3: probe output in oil, water and gas. The red-shaded area corresponds to voltage output when gas surrounds the tip of the probe. In favorable situations, water can be differentiated from oil Y coupler Flow Gas or liquid bubble Time Figure 1.2: The basic probe optoelectronic chain. Reflection of light to the photodiode is high in gas and low in liquid Threshold A ghost in the well In 1999, Schlumberger launched its latest logging technology into the Middle East, the PS Platform* new-generation production services platform. True to the spirit of a platform, combinability with new sensors is implicit. Now the * Gas Holdup Optical Sensor Tool is being introduced to extend the capabilities of the PS Platform. Gas Water Oil Figure 1.1: probe principle. In gas, a strong reflection is sent back. There is a weaker (or no) reflection in liquids Based on the architecture of the successful * holdup measurement tool, the tool uses an array of four optical probes that can detect less than 1% gas in liquid, or liquid in gas, allowing water-entry points in gas wells to be established. Gas and liquid holdups can be quantified for three-phase, flow-rate calculations. The tool can differentiate between condensate, and gas, and can be used to verify bubblepoint pressure. The probes are essentially rugged optical fibers. The principle of operation is shown in Figure 1.1. When the optical probe is immersed in gas a very strong reflection is sent back along the fiber optic that is converted to an electrical output by the opto-electronic processing chain (Figure 1.2). When the probes are immersed in liquid, the reflection is much weaker, or even zero. This creates a voltage output that is a record of the time the probe spends in the liquid and gas phases that can be interpreted quantitatively to give the local gas and liquid holdup around the probe. By combining the data from four probes, an accurate estimate of the borehole gas holdup can be derived. The amount of light reflected by oil and water varies slightly, and in favorable situations, all three phases can be distinguished and their holdups measured, see Figure 1.3. The red-shaded area corresponds to the voltage output when gas surrounds the tip of the probe, either as a bubble (in red) as shown or as the continuous phase. When oil (green) surrounds the probe another voltage is obtained, likewise for water (blue, shown as the continuous phase here). An automatic thresholding algorithm is used to split the signal into time spent in gas and hence time spent in liquid. This gives the gas holdup from the following relationship: Red time Y g = Total time The gas or liquid bubble count is another quantity that may be measured. It is related to the volumetric flow rate, and is usually expressed as a frequency: B c = Number of events Total time 6

3 By manual adjustment of the threshold, it is often possible to discriminate between the liquids, but the signal contrast is very weak compared to the gas liquid contrast, and can vary according to the oil and water properties. Therefore, the primary function of the tool is for gas holdup measurement. Detection of liquid entries in gas wells The detection of small liquid entries in gas wells is beyond the scope of conventional production logging measurements, such as spinners and gradiomanometers. As the probes are so small (much less than 1 mm in diameter), they can even detect liquid droplets in the form of a mist. Figure 1.4 shows a log from this situation. The spinner and gradiomanometer log is shown on the left, and shows no response to the water entry. The log on the right shows the impact of the droplets on the optical sensors. The left track shows the raw voltage waveforms. The spikes are caused by droplets impacting on the probe tips. The track on the right shows the interpreted holdup and bubble count, enabling this small entry to be precisely identified and quantified. Red represents the gas holdup and green the liquid holdup, which is very small. Gamma ray Relative bearing X700 X750 X800 X850 holdup gas holdup water holdup holdup Density bubble count Temperature Spinner Gas flow rate Oil flow rate Water flow rate Total flow rate bubble count bubble bubble rate count bubble count hydrocarbon bubble rate Figure 1.5: Oil entry identified with the tool. A combination of and data enables three-phase discrimination. probes distinguish between hydrocarbons and water. measurements distinguish gas from liquid and enable the detection of less than 10% oil Density, g/cm Spinner, rps 0 20 Oil holdup raw waveform bubble count (cps) Figure 1.4: Detecting a small water entry in a gas well 7

4 Identifying an oil entry in a three-phase well When a tool is combined with electrical probes, then robust three-phase discrimination is achievable. This combination is possible if a tool is combined with the PS Platform, with its inbuilt probes. The electrical probes distinguish between water and hydrocarbons. The electrical probes distinguish gas from liquid. The combined log provides powerful three-phase diagnostics, as shown in Figure 1.5. The tracks show (from left to right): The gamma ray log and tool orientation The water holdup. Dark blue represents 100% water and white represents 100% hydrocarbon. The display is top center and so the lighter colored hydrocarbon can be seen trickling along the top side of this deviated wellbore, entering at approximately X850ft, with dark red representing 100% gas. The gas entry can be seen at approximately X750ft, again with a top center display Quantified values of the holdups of water and gas The bubble count visual display from. The darker the colour the greater the number of bubbles entering the wellbore The bubble count visual display from The quantified bubble counts The interpreted fluid entry profiles. It is clear from the log that there is hydrocarbon entering the wellbore at approximately X850ft. The data cannot determine whether this is gas or oil. The data show gas holdup and bubble count increase at X750ft, but no gas is seen below this depth, therefore the lower entry is oil. X200 X400 X600 X800 X1000 X1200 X1400 X1600 X1800 X2000 X2200 X2400 Perf Water holdup Oil holdup Spinner rps Down hole gas oil ratio m 3 /bbl Figure 1.6: Detecting condensate in a gas well Measured depth 1:200 ft raw waveform Density (g/cm 3 ) Gas flow rate Oil flow rate bubble count (cps) bubble count 0 (cps) Pressure (psi) (cps) 90 0 (cps) 30 WFDE WFDE corrected Figure 1.7: Estimation of bubblepoint pressure 100 Bubblepoint

5 Distinguishing gas from condensate The tool electrical probes cannot distinguish between oil and gas, only water from hydrocarbons. In a gas well, this means that condensate droplets cannot be seen. With the tool, however, the condensate droplets can be directly imaged. Figure 1.6 shows how the tool enabled a gas oil ratio to be established for each producing interval. The capacity for obtaining extra oil from the top zone became apparent, and following reperforation of the top interval, 400 B/D more oil was obtained. The perforated intervals are shown on the left. The holdup image, next right, shows a water sump in blue, condensate in green, and gas in red. The next track shows the downhole gas oil ratio and spinner revolutions per second, with interpreted flow rates adjacent. The last track shows uncorrected and corrected well fluid densities. Estimation of bubblepoint pressure The ability of the optical probes to spot very small liquid or gas bubbles can be used to sense gas breakout from oil when pressure falls below the bubblepoint. Figure 1.7 shows the depth, voltage output waveforms from the individual probes, the pressure and then the bubble count. By examining the waveforms, the formation of bubbles at approximately X100 ft can be seen. Therefore, as the tool is logged upwards in the tubing, the appearance of the first gas bubbles can be spotted and this can confirm the bubblepoint estimate for the well. Tool architecture The tool is based on the same design principle as the tool. Some minor differences are due to the requirements of the opto-electronic signal and processing chain. Despite the small size of the probes, they are rugged and field-proven. Figure 1.8 shows the tool, including a close-up view of an optical probe. The tool can combine directly with the PS Platform. Figure 1.8: The gas holdup optical sensor tool operates within the PS Platform string. Four needle-sized optical probes are positioned on the centralizer arms Summary The tool is targeted specifically at gas and liquid holdup measurement in production logging. Many applications of this new technology have been reviewed. Table 1 summarizes some of the key features and benefits. The tool can be used in vertical, deviated and horizontal wells, and conveyed on wireline, coiled tubing or tractor. features and benefits Patented optical sensor Binary discrimination for gas and liquid Needle-sized probe Four robust sensors Automatic threshold setting Adjustable threshold setting Runs in combination with PS Platform string MTS telemetry output integrated into SPRINT* and BorFlow* software Table 1: The key benefits of the tool Fluid optical property measurements independent of mixture velocity, temperature, pressure, density, viscosity, salinity and deviation Direct, not inferred, measurement of gas Precision measurements, not influenced by wetting effects or high velocity, in all downhole environments Protected full wellbore coverage for vertical and horizontal wells Accurate holdup and bubble count values Oil and water discrimination possible with one tool Full production logging diagnostic capability in a single descent Fiber-optic technology achievable downhole with electrical conductor cable Wellsite quick look and comprehensive interpretation for multiphase and deviated wells Pinpointing Fluid Entries in Producing Wells. J. Rounce, C.P. Lenn, G. Catala. SPE53249, presented at MEOS, Bahrain, February

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