PITFALLS OF RUNNING CONVENTIONAL PRODUCTION LOGGING IN HORIZONTAL/HIGHLY DEVIATED WELLS: A CASE STUDY

PITFALLS OF RUNNING CONVENTIONAL PRODUCTION LOGGING IN HORIZONTAL/HIGHLY DEVIATED WELLS: A CASE STUDY Waqar Khan, Venkataraman Jambunathan, and Luis Quintero, Halliburton Copyright 2015, 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 56th Annual Logging Symposium held in Long Beach, California, USA, July 18-22, 2015. ABSTRACT With the rise in production from unconventional plays, horizontal wells have become increasingly common. Production logging in horizontal wells with multiphase flow has always been challenging. As the wells drilled over the past few years approach a maturing stage, it is increasingly necessary to evaluate the performance of the wells and identify water sources to help ensure proper reservoir management. As such, array tools were developed to overcome the limitations posed by a conventional production logging strings. This paper highlights several field cases of production logs run in an unconventional shale play. The production logging was performed with an array tool string, in which conventional production logging tools were also attached. Interpreting the conventional production logging tools separately from the array production logging tools highlights the limitations of using conventional production logging tools. It has been observed that the interpretation of results from conventional production logging tools in highly deviated wells is either pessimistic or optimistic, depending on the final configuration of the wellbore. Array production logging tools provide a complete picture of the wellbore; thus, leading to a more comprehensive interpretation. INTRODUCTION With the shift in trend of drilling more horizontal wells especially in shale plays, issues related to phase segregation have become important. In highly deviated wellbores, the fluid tends to segregate with heavier fluids (water) sitting towards the bottom of the wellbore and lighter fluids sitting towards the top of the wellbore. The issues arising with phase segregation have been dealt extensively (Frisch, et al. 2009). Conventional production logging tools are center-based tools. This works well in vertical wells in which phase segregation is not an issue. The center-based tools offer a good representation of the fluid profile across the wellbore. In highly deviated wells, the center-based tools tend to sit towards the bottom of the wellbore. Owing to phase segregation, lighter fluids travel towards the top of the wellbore; whereas, heavier fluids tend to flow towards the bottom of the wellbore. Because of this, center-based tools no longer provide a representative flow profile of the wellbore. To overcome the limitations of center-based tools, array tools were developed (Gysen et al. 2010). The velocity tool spinner array tool (SAT) has six spinners; whereas, the holdup tools, resistance array tool (RAT), and capacitance array tool (CAT) have 12 measurement probes. These tools have a relative bearing measurement, which allows the position of each sensor to be accurately determined. The tools are designed to have the sensors reading at the circumference of the wellbore. These tools when run in conjunction with the conventional tool string provide multiple measurements around the entire wellbore. Along with the array tools, the gas holdup tool (GHT) has also proven to be a major component in evaluating the flow profiles in highly deviated wells. The GHT uses a lowenergy cobalt-57 source and a sodium iodide detector located a short distance from the source and separated by a tungsten shield. The detector counts gamma rays scattered back from the production fluid to the detector; the magnitude of the count rate is directly related to the gas holdup. The measurement is not affected by the composition and density of 1

materials outside the casing (Frisch, et al. 1998). This paper examines two production log surveys carried out in an unconventional shale play. This paper highlights the merits of running array-based production logging tools in highly deviated wells, and the drawbacks associated with attempting to interpret a production log run in a highly deviated well with traditional production logging sensors only. ARRAY PRODUCTION LOGGING TOOLS SPINNER ARRAY TOOL (SAT) The SAT (Fig. 1) consists of six miniature spinners mounted on the inside of a bow spring. The tool is closed while running in hole and opens automatically when it leaves the tubing and enters the larger diameter of the casing. The array tool has a relative bearing system, which allows for the accurate determination of the position of each spinner in the wellbore. Because the SATs measure at the pipe wall, the spinner does not require any correction for true fluid velocity. The calibration for the SAT spinners is similar to the calibration of conventional center-based spinners. Fig. 2 shows an example of spinner calibration. RESISTANCE ARRAY TOOL (RAT) The tool has an array of 12 miniature sensors mounted on the inside of a bow spring. Each sensor senses the apparent resistance of the fluid at a specific point across the area of the pipe. The monitored resistances, as they vary with position and time, can be interpreted to improve the understanding of what is flowing through the pipe. The tool functions on the principle of water and hydrocarbons (oil or gas) not forming a homogenous solution, rather one is always present in the other as an emulsion or dispersed phase. Generally, water contains sufficient salt to make it significantly lower in resistivity than hydrocarbons. Fig. 3 Resistance array tool (RAT). CAPACITANCE ARRAY TOOL (CAT) The tool uses an array of 12 microcapacitance sensors, which are radially distributed in the wellbore. The tool works on the principle of oil, gas, and water having different dielectric constants. While the RAT is good at distinguishing between water and hydrocarbons, the CAT allows for the differentiation of oil and gas. Fig. 1 Spinner array tool (SAT). Fig. 4 Capacitance array tool (CAT). INTERPRETATION OF PRODUCTION LOGGING DATA For both traditional and array-based sensors, commercially available software has been used in the interpretation of the production logging data. The software uses a global probabilistic method to obtain the flow profile. The details and working of the software have been explained in the literature (Gysen et al. 2010). Fig. 2 Calibration of SAT spinners. 2

WELL 1 This is a horizontal well completed with 40 stages across which a 4.5-in. casing has been run. Owing to wellbore conditions, only 14 stages could be logged. At the time of logging, the well was producing 530 BOPD, 995 Mscf/D and 130 BWPD. remaining sensors appear to be responding. Fig. 5 shows the production logging tool string run across the completed interval. Along with the traditional production logging sensors, array tools encompassing the SAT, RAT, and CAT along with the GHT was run. Fig. 6 Traditional production logging sensors. Fig. 5 Production logging tool string. To highlight the pitfalls of solely running traditional production logging sensors in highly deviated wells, two interpretations were carried out. One of the interpretations used all the sensors run in the tool string; whereas, the second interpretation used only the traditional production logging sensors to see how the flow profile is impacted. Fig. 6 shows the response of the traditional production logging sensors across the logged interval. Apart from the inline spinner, all the 3 Fig. 7 shows the response of the SAT across the logged interval. Apart from the inline spinner, all the remaining sensors appear to be responding. Some noise interference is observed on the DOWN 60 fpm pass. This can be fixed by running a filter over the pass. Fig. 8 shows the array spinner response in an image format. This allows for a better understanding of the array response. The center of each track is the bottom of the wellbore; whereas, the edges correspond to the top of the wellbore. Except for the UP 90 fpm, all passes show a consistent response across the logged interval with the heel observed as a contributor to the flow. In Fig. 9 across the black dotted line, the center-based spinner is not seeing any deflection (i.e., it is not seeing any flowing coming from the frac stage). Based on the spinner array tool rotation curve (SATROT), array spinners 4, 5, and 6 would be towards the top of the wellbore; whereas, array spinners 1, 2, and 3 would be towards the bottom of the wellbore. Array spinners 1, 2,

and 3 are not seeing any deflections, indicating there is no fluid movement at the bottom of the wellbore. These spinners would be detecting the heavier phase present in the wellbore; in this case water. The center-based spinner, owing to the weight of the tool, will also be sitting towards the bottom of the wellbore, and reading the heavier phase fluid (water). Array spinners 4, 5, and 6 would be detecting the fluid moving towards the top of the wellbore (i.e., lighter fluid). Array spinner 5 would be reading at the highest point in the wellbore. It sees a definite deflection, indicating gas flowing from the fracturing stage across this depth. With traditional sensors, this could have been easily interpreted as a stage not contributing to the total fluid flow. In the same figure across the red dotted line, the center-based spinner is seeing negative flow, indicating fluid is travelling down the wellbore. Across this point, based on the deviation curve, one would expect the heavier phase fluid (water) to be flowing down the wellbore. Array spinners 3 and 4 are detecting flow at the bottom of the wellbore; they also detect negative flow (i.e., heavier fluid moving down the wellbore). Array spinners 1 and 6 are reading towards the top of the wellbore; sharp deflection is observed across both spinners, indicating flow from the fracturing stage. Using only traditional sensors, it would have been difficult to interpret flow across this fracturing stage. Fig. 12 shows this to be a producing zone in the final interpretation. Producing zones can easily be masked or misinterpreted as thief zones; thus, leading to a pessimistic flow profile. In the case of center-based holdup tools, it is difficult to interpret a complete picture of the wellbore. Fig. 13 shows the production profile based off of the conventional production logging sensors; whereas, Fig. 12 shows the production profile based off of the array production logging sensors and the conventional sensors. Comparing Figs. 12 and 13, the flow profile based off of the conventional sensors is pessimistic. It indicates some of the stages are not producing when in reality array sensors are able to pick the production across those stages. The last logged stage shows a significant production not visible on the conventional spinner, owing to the water fallback observed across this stage. The water fallback is also observed on the array spinners reading towards the lower side of the wellbore, but the spinners towards the top show a sharp deflection to the right, indicating significant production across this stage. Fig. 10 shows how the resistance array tool highlights a complete picture of the wellbore as opposed to the traditional sensor-based sensors. While the readings vary between water and hydrocarbons on the density and capacitance tools, the resistance array tool shows hydrocarbons to be present towards the top of the wellbore with water present at the bottom side of the wellbore. Similar to SAT image, the center of the track represents the bottom of the wellbore with the edges representing the top of the wellbore. As explained above, an interpretation based on the conventional sensors alone would not lead to a representative production profile. 4

Fig. 7 Spinner array tool (SAT) with the inline and continuous flowmeter. Fig. 8 Spinner array tool response in an image format. 5

Fig. 9 Deflection observed on the array spinners is not seen on the center-based spinner owing to the fallback of heavier-phase fluids. Fig. 10 Comparison of traditional holdup sensors and RAT array resistivity sensor. RAT shows a comprehensive picture of the wellbore, highlighting the sump areas. Fig. 11 Velocity and holdup profiles generated from array tools. This is further optimized by including the center reading data in the analysis. The velocity and holdup profiles clearly indicate segregated flow between water and hydrocarbons. 6

Fig. 12 Flow profile based on the array production logging tools. Fig. 13 Flow profile based on the conventional production logging tools. Stages which are contributing are masked in the conventional sensors owing to downflow of heavier-phase fluids. WELL 2 SAT, CAT, and RAT array production logs were run with conventional sensors in Well 2 with the objective of estimating the flow profile and the contribution from the perforation stages. The well is horizontal with 40 perforation stages. The logging interval did not cover all the perforation stages; and therefore, there will be some flow observed from below the logging interval. The well was reported to be producing 400 STB/D oil, 250 STB/D water, and 1,400 Mcf/D gas. 7 The conventional log data is presented in Fig. 14. A quick look at the spinner response gives the impression the flow is erratic or slugging. The spinner and holdup response from the down pass made at 30 ft/min is presented in Fig. 15. Comparing the spinner response with the center reading holdup tool response shows the spinner is responding to the different phases flowing in the wellbore. The spinner response appears to be either dominated by the oil phase or the water phase. As the wellbore is horizontal and the flow rates are relatively low, phase segregation is expected and the oil, water, and gas phases will be flowing at different velocities. The holdups could change because of changes in the wellbore trajectory. When the flow is downhill, the heavier phase tends to flow faster with low holdup. For uphill flow, the heavier phase tends to flow slower with higher holdup. Recirculation of water within the wellbore is possible, which further complicates the flow profile interpretation. A center reading spinner will be located in the center of the wellbore, and its response will be dominated by whichever phase is occupying that region. The flow profile estimated using the center reading tools is presented in Fig. 16. It suggests only a few stages are contributing to the total flow. This will be compared to the flow profile generated using the combination of array and conventional center reading production log sensors. The SAT, RAT, and CAT responses are shown in Figs. 17 19. The velocity and holdup map presented in these figures are from down pass made at 30 ft/min. The CAT response was better for this pass as compared to other passes, and this was selected for the interpretation. In the other passes, four CAT sensors were not working as compared to three in the down 30 ft/min pass. In the horizontal wells, one has to exercise caution while averaging passes. The mode of conveyance in this well was coiled tubing, and there can be some surge and swab effects caused by the movement of the coiled tubing in the wellbore. The up and the down passes can have slightly different flow profile. Only the passes with similar flow and holdup response should be averaged.

The holdup profiles from the CAT and RAT sensors are consistent with each other and with the other center reading sensors. The CAT response did not clearly indicate free gas in the wellbore; and hence, the array tools were used to provide estimates of water and oil holdups. The velocity and holdup profiles along with the initial flow profile estimation are shown in Fig. 20. In addition to the array sensors, fluid density from the center reading tool was integrated, and based on the measured density and the input fluid properties, some small amount of free gas is initially estimated downhole. This profile will be further optimized by integrating center reading velocity and capacitance water holdup. As the array holdup tools did not indicate any free gas in the wellbore, all the produced gas was assumed to be coming from the solution. Fig. 21 shows the final flow profile after global optimization. The profile appears to be very different from the one estimated using just the conventional sensors. The flow profile is much better because it takes into account the flow segregation and the phase velocities. The profile suggests the water produced is coming from below the logged interval. Eight of 18 perforation stages are producing oil and gas. A closer look at the temperature profile indicates a few more stages could be contributing, but these are not picked up by the tools as the contributions could be minor. Fig. 14 Conventional log data. Three up and three down passes were made at 30, 60, and 90 ft/min. Each of the passes is illustrated using a different color. The gamma ray and casing collar locators were used for correlation and depth control. 8

Fig. 16 The flow profile along with the contribution from the different stages at surface conditions. This flow profile was generated using just the conventional production logging tools, such as the inline spinner, density, and capacitance. It appears only a few stages are contributing to the total flow. Fig. 15 The water and gas/oil phases are flowing at different velocities. Some of the changes seen in the center reading spinner response are because the spinner is responding to the different phases flowing at different velocities. Fig. 17 Velocity profile after spinner calibration. The spinner calibration was conducted using the data from all the passes. The velocity profile is from down pass at 30 ft/min. The left edge of the velocity profile track is the bottom of the wellbore and the right edge is the top. For segregated flow, depending on the well trajectory, the water or hydrocarbon can have a higher velocity. 9

Fig. 18 The holdup profile after RAT calibration. The water/hydrocarbon values were entered for each probe and used for calibration. The holdup profile map is from down pass at 30 ft/min. The left edge of the holdup profile track is the bottom of the wellbore and the right edge is the top. The holdup is influenced to a large extent by the well trajectory. Fig. 19 The holdup profile after CAT calibration. The water/gas values were entered for each probe and used for calibration. The CATs do not show any clear indication of free gas downhole. For the calibration, the surface capacitance values for air were used. The holdup profile map is from down pass at 30 ft/min. The left edge of the holdup profile track is the bottom of the wellbore and the right edge is the top. Some of the sensors were not working and were ignored for the holdup calculation. The holdup is influenced to a large extent by the well trajectory. The water holdup estimated is consistent between the resistance and capacitance array tools. 10

CONCLUSIONS Interpretation based on conventional tools only in highly deviated wells would not be representative and can be pessimistic at times. It is challenging to interpret horizontal production logs given the complexities arising because of well trajectory and segregated flow behavior. Array production log sensors along with conventional center-based sensors are recommended for use in horizontal wells. Fig. 20 The velocity profile and the holdup profiles from resistance and capacitance array tools are used to generate the initial flow profile. This is further optimized by including the center reading data in the analysis. The velocity and holdup profiles clearly indicate segregated flow between water and hydrocarbons. REFERENCES Frisch, G.J., Dorffer, D.F., Marshall J., Zett, A., and Webster, M., 2009, Improving the process of understanding multiprobe production logging tools from the field to final answer: SPE-125028-MS, SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 4 7 October. Frisch, G., Waid, M., Kessler, C., and Madigan W., 1998, Gas holdup tool applications in production logging: SPWLA-1998-I, SPWLA 39th Annual Logging Symposium, Keystone, Colorado, 26 28 May. Gysen, A., Gysen, M., Zett, A., Webster, M., and Calero G., 2010, Production logging in highly deviated and horizontal wells: moving from qualitative to quantitative answers: SPE-133479-MS, SPE Annual Technical Conference and Exhibition, Florence, Italy, 19 22 September. Fig. 21 Flow profile along with the contribution from the different stages at surface conditions. There is no water inflow from the stages logged and all the water appears to be coming from below the logged interval. The flow profile appears to be very different from the one estimated using just the conventional sensors. The flow profile is much better and suggests contribution from many more stages. 11