1A New Multiphase Holdup Tool for Horizontal Wells

Nicholas D. Ryan - Sondex Ltd. UK Derek Hayes Sondex Ltd. UK

Presented at the SPWLA 42nd Annual Conference, Houston. June 2001

ABSTRACT

Traditional PL analysis requires phase holdup and fluid velocity measurements. Flow in a horizontal well may feature regions of segregated, intermittent and distributed flow, the principle reason being segregation of different density fluids combined with the effects of well deviation (no horizontal well is truly horizontal). Because of phase separation, the measurement of true holdup in horizontal wells using centre-sampling PL tools is difficult, if not impossible. As an approach to obtaining a true holdup in horizontal wells, a new tool has been developed which uses multiple sensors that can be deployed either around the circumference of the pipe or at dual radii. Being at the same depth position in the well, the sensors measure phase holdup with greater confidence. The sensors used are micro-capacitance sensors, which respond to the permittivity (dielectric constant) of the surrounding fluids. Capacitance sensing circuits output different frequencies for gas, oil and water making this a 3 phase tool. The tool is termed the "Capacitance Array Tool " (CAT).

DEVELOPMENT OF THE TOOL.

The tool consists of a multi arm tool with electronics at the top, a finger section in the middle and a motor section at the bottom. The sensors are deployed in arms, which are motored open and closed in response to commands from surface.

Frequency measurements from each of the 12 sensors are transmitted back to the surface. The first prototype tools had 24 arms (Fig.1) but were considered to be overly disruptive to the normal

flow pattern; therefore the number of arms on the production tool has been reduced to 12 (Fig.2). The final radial position of the arm is selected by a machined angle at the base of the arms giving the operator a choice of sensor distribution (see Fig.4 and Fig.5). As the tool may rotate during logging an internal sensor is used to determine the high side of the hole at all times.

SENSOR TECHNOLOGY AND SENSOR RESPONSE

The sensors of the tool (Fig.3) are in principle simple and essentially consist of a single electrode. Because of the very low value of capacitance measured it is imperative to have near perfect insulation throughout the 177 degrees centigrade, 15000 psi range of the tool. This has been achieved through careful selection of electrode materials and precise assembly procedures. The electrode assembly is enclosed in a special casing, which provides the desired electrical characteristics. Metal bonding techniques are then used to encapsulate the sensor assembly. To prevent contamination by fluids bridging between the arm and the sensor, the supporting arms are kept clear of the sensor and the sensor is coated with a proprietary material to minimise adhesion of the

Fig.2: 12 Arm Dual Radius CAT

Fig.1: Prototype 24 arm CAT

2liquid phases. Signals are communicated between the probes and the main body of the tool via corrosion resistant tubing with metal to metal sealing for low maintenance. Responding to the capacitance value around the probe the oscillator circuits produce a low frequency in water, high frequency in oil and a higher frequency in gas. Sensor frequencies are typically sampled 72 times per second (dependent upon the telemetry) and relayed to surface where they can be processed for presentation.

The sensor response in mixtures is similar to that of conventional capacitance tools, which exhibit a non linear response in relation to whether the dominant phase is conductive or non conductive. The sensors have a radius of investigation of about 3mm. The environment that the tool will be run in and the fact that the sensors are micro means that they are expected to measure the individual segregated phase that surrounds them rather than emulsions (though the tool will work in emulsions). Thus the sensors will in most situations report either gas, oil or water. The outer sensors are positioned 0.3" (7.6mm) from the casing ID which results in a minimum measurable holdup of 3-7% in a stratified flow, depending on tool rotation (Fig.4). If desired, the inner sensors can be pre-configured on a fixed diameter of approximately 3" (76mm) (Fig.5), or alternatively, all the sensors can be on a single diameter at a position away from the pipe wall. This arrangement may prove to give better results in vertical and deviated pipe sections.

CALIBRATION

In common with conventional capacitance tools, The sensors deliver frequency ratios of approximately 3.7:3.0:1.0 over the gas oil water range. Each sensor has unique end points and is thus the tool is calibrated in air, oil and water to

normalise the response. Ideally, calibration is performed downhole. For liquids the end point values do not change dramatically from surface to downhole, however with gas, permittivity changes with pressure and temperature, thus downhole calibration is recommended. The recorded data can also be post job re-calibrated.

LOGGING

The tool is run between centralisers in combination with standard PL tools such as temperature and flowmeters. Logging can be either depth based when pulling out of hole or by logging station. Logging stations have the advantage of giving a time based average holdup and allowing the visual identification of differing flow regimes.

HOLDUP MEASUREMENT

For a tool with sensors at the casing ID (Fig 4)

holdup may be calculated geometrically. Holdup is the fraction of the wellbore that a phase occupies;

Fig 3: Micro Capacitance Sensor, Scale in cm. The sensing element is within the small tube.

Fig.4: 12 Sensors at Single Radius (Casing ID)

Fig.5: 12 Sensors at Dual Radii

3therefore in terms of fluid level the correlation is non linear. For example using a centred 1 11/16" (43mm) tool in 6.3 (160mm) ID horizontal casing a change from 0 to 10% holdup at the bottom of the pipe will show a fluid level change of 0.94 (23.9mm) whereas a change from 50% to 60% holdup will result in a fluid level change of 0.60 (15.2mm) This means that the tool is more sensitive at high and low holdups. It is thought that a good way to evaluate inflow of a horizontal well is to observe flow at the peaks and troughs where either the light phases are squeezing though or the heavy phase is spilling over. In this environment the tool is particularly useful. For plug and slug flow regimes, time based averages are used to output phase holdups.

For dual radii tools the holdup calculation is not so straightforward, as though the inner arms are at fixed radii, the outer arms are at variable radii depending upon casing ID (Fig. 5). The user is required to input casing ID to be able to calculate holdup.

IMAGING OF DATA

Visualisation or imaging is a first-rate way to transmit complex information as it allows the downhole holdup profile to be seen in a way similar to that of the viewer standing alongside or facing the wellbore. The sensor density and the fact that all the sensors are at the same depth position in the well allows us to image the dynamic holdup information produced by the tool. The CatView software provides a sophisticated approach to both calculating and displaying multi phase holdup. There are several options, which allow the user to visually tune the image (and thus the correct calculated holdups). Normalised sensor readings are mapped to both colour and phase-content, using a multipoint data table. Real time interpolation generates actual values for RGB colour and Yw, Yo and Yg fractions for the fluid local to each sensor. The whole cross-section is then calculated on the basis of distances from all the active sensors, so that a point close to and mid way between two sensors will be assigned an average value. The algorithm allows all sensors to contribute to every part of the cross section, with a weighting based on inverse distance, raised to any power. Experiments have shown that inverse square weighting gives good results, but users can choose any power. In order to achieve optimal results it is preferable to use vertical distance rather

than absolute distance for the weighting function. This is possible thanks to the tools built-in high-side sensor, and recognises tendency for the phases to exhibit horizontal segregation. The extra information can be used to improve the calculations. The user is provided with controls, which permit the choice of vertical or absolute distance weighting or a mixture of the two. Because the chosen weightings have immediate effect on the coloured image, it is easy to select the optimum settings (Fig.6). In vertical hole, for example, the vertical distances have no meaning, and absolute distance would be used. Numerical values for Yw, Yo, and Yg are displayed directly on-screen, and can be output, together with the sensor readings, to an LAS file for input into

analysis software.

For horizontal well analysis phase holdup is one half of the solution, the other is knowing phase velocity. Though the illusion is of velocity when viewing moving interfaces by time drive, the tool is actually telling us how long it takes for a bubble to pass the sensors. Thus it cannot identify the difference between a short bubble travelling slowly and a long bubble travelling fast. Phase flowrate tools do exist and others are being developed however fullbore spinner data together with slip velocity models can be used to provide phase velocity. One approach to obtaining phase velocity is by using tandem CAT tools to cross correlate transit time of interfaces between tools of known axial separation. From the transit time the fluid velocity can be determined.

FLOW LOOP RESULTS.

The tool has been tested in horizontal, near horizontal and deviated flow loops trials. These trials show not only that stratified flow can be

Fig. 6: CatView of stratified 3 phase flow. Yw 0.610, Yo 0.245, Yg 0.144

4detected and imaged but that downhole flow regimes and flow patterns can be identified.

Slug flow pattern in a horizontal flowloop

Figure 7 is a time based 3D image. The holdup of all 3 phases is visible. A slug can be seen before and where the oil meets the top of the flow loop. This tells us the flow regime and an average of the readings will give us a better idea of holdup.

Figure 8 is a side view of slug flow data.

Segregated flow in a deviated flowloop.

Fugure 9 is a side image comparing video camera data and CAT data in a flowloop deviated 45 degrees. This is 2 phase flow of oil and water. Segregation of the heavier phases to the lower side of the hole is apparent in the CAT image but to a lesser extent in the video data. The CAT will give a better holdup estimation than centre sampling tools and may help to explain anomalous spinner responses.

CONCLUSIONS

By deploying multiple multi phase sensors in a radial pattern it is possible to measure across-wellbore segregated holdup and to detect fluids which would not be seen by centre sampling tools. In horizontal wells this will provide invaluable information especially at peaks and troughs where phases are either squeezing through or spilling over. To convey the large amount of information 3D visualisation software is used which can be tuned by the interpreter before writing an output LAS file of individual phase holdup. The next advances will be to combine segregated holdup data with individual phase flowrates. For the moment interpretation is by measuring total flow and using slip velocity correlations.

The tool will be undergoing field trials in Mid 2001

ABOUT THE AUTHORS

Nicholas Ryan, BSc, SPE works in sales and field support for Sondex Ltd, Bramshill UK.

Derek Hayes, PhD works in tool development for Sondex Ltd, Bramshill UK.

CREDITS

The development of this tool has been sponsored by Halliburton Energy Services, Logging and Perforating division.

The tool and sensors have been developed by Derek Hayes and Noel Bernatt at Sondex.

Fig.7: CatView of Slug flow Yw 0.635, Yo 0.283, Yg 0.082

Fig.8: Slug flow viewed from the side

Fig 9: Holdup image and video still of 2 phase diesel-water flow at 45 degrees deviation.