U sing fibre-optic cable to detect strain, vibration, and temperature is not new. Distributed sensing techniques such as distributed temperature sensing (DTS), distributed acoustic sensing DAS), distributed strain sensing (DSS), and distributed vibration sensing (DVS) are all commonly used technologies in the energy industry. Over the past decade, deploying fibre-optic cable into wellbores and along pipelines has become an industry accepted practice for surveillance, diagnostics, and to trigger real time alarms of events or condition changes. In downhole applications, DTS and DAS are the most commonly used distributed sensing technologies. DTS can be used for production profiling, casing leak detection, stimulation optimisation and diagnostics, flow monitoring and diagnostics, identifying fluid levels, and steam assisted gravity drainage (SAGD) applications. DAS is used to provide qualitative data that can be used for casing leak detection, stimulation diagnostics, frack ball seat engagement confirmation, production profiling, electronic submersible pump (ESP) diagnostics, and optimising coiled tubing intervention operations. Fibre-optic installations range from (a) permanently installed as part of the well completion, to (b) strapped to tubulars hung off in the wellbore, or (c) intervention strings that are run into the wellbore periodically to conduct distributed sensing surveys. This article will focus on downhole applications of DTS and will present one case study. DTS inside the wellbore Why distributed sensing? Noninvasive techniques are key to measuring any parameter. Regardless of the parameter being measured, the measurement strategy should not interfere with the parameter of interest. DEPLOYING DOWNHOLE SCOTT SHERMAN, TRICAN WELL SERVICE, CANADA, EXAMINES THE USE OF DISTRIBUTED TEMPERATURE SENSING (DTS) IN DOWNHOLE APPLICATIONS.
Transcript
Using fibre-optic cable to detect strain, vibration, and temperature is not new. Distributed sensing techniques such as distributed temperature sensing (DTS), distributed acoustic sensing DAS),
distributed strain sensing (DSS), and distributed vibration sensing (DVS) are all commonly used technologies in the energy industry. Over the past decade, deploying fibre-optic cable into wellbores and along pipelines has become an industry accepted practice for surveillance, diagnostics, and to trigger real time alarms of events or condition changes.
In downhole applications, DTS and DAS are the most commonly used distributed sensing technologies. DTS can be used for production profiling, casing leak detection, stimulation optimisation and diagnostics, flow monitoring and diagnostics, identifying fluid levels, and steam assisted gravity drainage (SAGD) applications. DAS is used to provide qualitative data that can be used for casing leak detection, stimulation diagnostics, frack ball seat engagement confirmation, production
Fibre-optic installations range from (a) permanently installed as part of the well completion, to (b) strapped to tubulars hung off in the wellbore, or (c) intervention strings that are run into the wellbore periodically to conduct distributed sensing surveys.
This article will focus on downhole applications of DTS and will present one case study.
DTS inside the wellbore
Why distributed sensing?Noninvasive techniques are key to measuring any parameter. Regardless of the parameter being measured, the measurement strategy should not interfere with the parameter of interest.
DEPLOYING
DOWNHOLESCOTT SHERMAN, TRICAN WELL SERVICE, CANADA, EXAMINES THE USE
OF DISTRIBUTED TEMPERATURE SENSING (DTS) IN DOWNHOLE APPLICATIONS.
| Oilfield Technology Reprinted from September 2016
Production logging (PL) and other commonly used technologies for well profiling require stopping and restarting well production multiple times, pumping fluids into the well as the PL tools are run into the well, and moving the PL tools along the wellbore.
Distributed sensing has the advantage in that fibre-optic cable based measurements are completely passive and do not effect downhole conditions. Depending on the fibre-optic application, the entire wellbore can be profiled without cable movement. If the fibre is permanently installed in the wellbore when a distributed sensing survey is desired,
an interrogator is connected to the fibre on surface and the survey is run without impacting production.
Because distributed sensing methods are passive they do not require cable movement, the surveys are less risky and are more representative of ‘normal’ well conditions, and hence more accurate than PL surveys. The advantage of distributed sensing is that it provides both steady state production profiles as well as dynamic wellbore effects associated with shutting in and restarting production.
Running fibre into the well inside an intervention string can have a minor impact on flow dynamics in the wellbore because of the reduced flow aperture of the wellbore while the intervention string is in place, however, the flow aperture is reduced uniformly throughout the wellbore provided the coiled tubing string is run to the toe of the wellbore.
Fibre-optic cable deploymentFibre-optic cable can be deployed into the wellbore on the outside of the casing when the well is drilled as illustrated in Figure 1 (Left), strapped to the outside of the production tubing when the well is completed as shown in Figure 1 (Centre), or merely inserted into the wellbore periodically for distributed sensing surveys, shown in Figure 1 (Right). Coiled tubing is typically used to convey the fibre-optic cable into the wellbore for short surveys. Fibre-optic cable can also be conveyed into the wellbore using common wireline techniques. Carbon-fibre rods containing fibre-optic cables have been used for distributed sensing surveys with some success in the North Sea.
Deciding which avenue to deploy fibre into the wellbore is most suitable depends on a number of circumstances. Some advantages and
disadvantages of the various deployment strategies are shown in Table 1.
For economic reasons, less than 1% of new wellbores have fibre-optic cable permanently installed as part of the completion when they are drilled. A higher percentage of SAGD wells have fibre strapped to production or injection strings that are hung off in the wellbore as part of the completion process than other well types but the numbers of these semi-permanent installations are still relatively few. Running an intervention string such as coiled tubing that contains fibre-optic cable is the most cost-effective method to perform DTS surveys.
Downhole DTS applications
Production profilingDTS is cost comparative to conventional production logging techniques that rely on spinners and other instrumentation
Figure 1. (Left) Cross section of fibre install. (Centre) Cross section of FIMT strapped into production tubing. (Right) Cross section of fibre inside coiled tubing intervention string.
Table 1. Advantages and disadvantages of fibre deployment techniques.
Fibre installed outside casing
Fibre strapped to production tubing
Fibre conveyed inside coiled tubing
Advantages - Least invasive measurements.- Can be used during well stimulation.- Can be used with DAS for microseismic surveys.
- Fairly noninvasive measurements. - Can be used to determine the fluid level within the vertical section.- Can be replaced when production tubing is pulled.- Can be added to existing wells.
- No capital costs to operators. - Can be used during well stimulation in some circumstances.- No risk of damage during well completion operations.- Allows distributed sensing surveys in wells without fibre installations.
Disadvantages - High risk of damage during completion, perforating or stimulation operations.- Cannot be repaired or replaced.- Upfront capital investment required when well is drilled.
- Risk of damage while installing production tubing.- Requires that production tubing be installed in the wellbore.- Usually production tubing does not extend to the toe if the wellbore.- Upfront capital cost is required when well is completed.
- Coiled tubing does reduce the flow aperture of the wellbore during distributed sensing surveys.
Table 2. Production profile.
Stage number Flow rate (e3m3/day)
Contribution (%) Stage number Flow rate (e3m3/day)
Contribution (%)
Frack port 26 11.2 5.5 Frack port 15 1.4 0.7
Frack port 25 5.9 2.9 Frack port 14 8.1 3.9
Frack port 24 17.1 8.3 Frack port 13 1.4 0.7
Frack port 23 19.5 9.5 Frack port 12 9.0 4.4
Frack port 22 3.1 1.5 Frack port 11 3.8 1.9
Frack port 21 15.9 7.8 Frack port 10 2.3 1.1
Frack port 20 5.3 2.6 Frack port 9 5.2 2.5
Frack port 19 7.5 3.7 Frack port 8 3.0 1.5
Frack port 18 7.3 3.6 Frack port 7 0.12 0.10
Frack port 17 22.2 10.8 Frack port 6 1.5 0.70
Frack port 16 26.1 12.7 Frack port 5 5.2 2.5
Total 141.1 68.8% Frack port 4 0.77 0.40
Frack ports 1 - 3 22.2 10.8
24, 23, 21, 17, 16 100.8 49.1% Total 64.0 31.2%
Reprinted from September 2016 Oilfield Technology |
components to infer the flow dynamics within the wellbore. Using passive sensing measurements of discrete temperature changes throughout the entire wellbore, DTS detects flow every meter along the rock face. Conversely, conventional production logging tools can only detect flow within the casing; they only see additional flow where it enters the casing as shown in Figure 2.
The ability to detect flow all along the rock face is of particular interest in openhole completions. DTS is able to pinpoint the production along the interval between packers and detect flow around packers. Production logging techniques can not differentiate between production from adjacent intervals and production from the interval
that ‘should’ be flowing through a given frack port or perforation interval, so this skews the production survey.
Zones that underperform adjacent intervals appear to produce better than they actually do when conventional production logging techniques are used for production profiling.
Fibre can be installed permanently, semi permanently, or run in coiled tubing for production profiling. Permanent installations outside the casing provide the most accurate direct measurement, however, fibre in coiled tubing provides results that are sufficiently accurate and are preferred to fibre strapped to production tubing that does not typically extend to the toe of the wellbore.
Casing leak detectionDTS can be used to locate and measure Joule-Thompson (JT) effects of unexpected casing inflow. Conventional techniques to locate casing leaks involve using a microphone and moving it within the wellbore to find the ‘noisiest’ area of the wellbore. Assuming there are no perforations at this location, this is assumed to be the site of the leak. Selective packer tools are often used isolate the suspected leak spots to confirm that the leaks were located using the acoustic technique.
In this application, the fibre can be located outside the casing, strapped to production tubing, or run inside a coiled tubing work string.
Stimulation optimisationDTS can be used to optimise various types of stimulation treatments. The key benefit to using DTS is the ability to use time-lapse measurements to visualise where the injected fluid is going every 30 seconds and make adjustments
on-the-fly in the field.
Matrix stimulation – diversion optimisationUsing DTS to optimise matrix acidising has gained a significant amount of traction in Saudi Arabia and other geographic regions over the past five years. Numerous technical papers have been published on the benefits of using DTS to measure the effects of diversion techniques. Some case studies that have been published claim production increases of up to eight times over prior acid stimulations. The key benefit is that DTS can determine the effectiveness of the diversion strategy before the acid treatment is pumped and the diversion strategy can be adjusted accordingly. This allows new rock to be stimulated, hence the subsequent gains in production.
In this application, the fibre can be permanently installed in the wellbore or installed in the coiled tubing work string used for the stimulation treatment.
Limited entry fracks – adjust ratesLimited entry is a technique where the flow ports (perforations or orifices) are sized to generate sufficient back pressure. This back pressure causes the frack fluid to divert to other ports. In ideal conditions, this results in an even distribution of stimulated perforations. Unfortunately, no source rock is homogenous and ideal conditions do not exist in very many oilfields. Downhole cameras have been used to show that not all perforations in a limited entry completion participate in the frack. Figure 3 shows frack ports located at the same depth within a horizontal wellbore in Western Canada. By looking at the erosion alone, it is obvious the three of the five ports shown took fluid whereas the others did not. On this particular frack, the pump rate was 3000 l/min (18.87 bbls/min) through fifteen 11 mm (7/16 in.) ports.
Figure 2. DTS versus PL comparison.
Figure 3. Frack ports located at the same depth within a horizontal wellbore in Western Canada.
Figure 5. Pressure and flow rate during DTS survey.
| Oilfield Technology Reprinted from September 2016
DTS can be used to optimise limited entry fracks. By monitoring frack placement in real time, flow rates can be increased to ensure that every perforation cluster is active, provided sufficient pumping horsepower is present on location. Refracturing operations on existing wells benefit similarly because ‘thief zones’ can be identified immediately and corrective actions can be taken to divert the treatment to other zones.
For limited entry frack optimisation, fibre is ideally permanently installed in the wellbore, outside the casing. It is not usually practical to have a coiled tubing string inside the wellbore during fracturing operations unless the coiled tubing is being used as the conduit to place the frack.
Case study: production profiling
Objective: develop a better understanding of inconsistent well to well productionThe operator has an active field consisting of several wells on pads in a particular play in Western Canada. Each of these wells has varying levels of production even though the formation is considered to be fairly homogeneous. One well in particular is a significantly better producer than the others in the field. Knowing how this well was completed and understanding that every stage does not contribute to production equally, the hope was to learn what went ‘right’ with this well and apply it to other wells in the area on future completions.
The operator’s key objectives were: Ì Determine where within the wellbore the production is coming
from (production profile).
Ì Measure the effectiveness of the fracture stages in the horizontal lateral.
Ì Determine which parameter(s) (gas ratio, gas counts, total organic content, frack tonnage, frack rate, etc.) correlated with the best producing stages of a top producing well.
Ì Determine the production profile after ~50% estimated ultimate recovery (EUR).
Well detailsThe well was completed according to standard Western Canadian horizontal well completion practices using a 26 stage ball drop – open hole system as shown in Figure 4. 55 t of sand was placed into each zone using a slickwater fluid system. The amount of fluid in the pad used to initiate the fracks did change from zone to zone but otherwise the frack programme was consistent for all 26 intervals.
Production surveyThis well had been on production.
Fibre deploymentA 5800 m (19 000 ft) long 60.3 mm (2 ⅜ in.) coiled tubing string containing an electrical conductor, single-mode and multi-mode fibre-optic cable was dispatched to location. Only the multi-mode fibre was used for the DTS survey on this job however this string is capable of being used for DAS and with conventional logging tools. The coiled tubing conveyance string can be used for conventional coiled tubing applications, even during distributed sensing surveys.
The well was shut in while coiled tubing conveyance string was run into the wellbore. The operator would not allow any fluid to be pumped into the wellbore during this operation, resulting in an inability to use normal coiled tubing extended reach
Figure 6. Raw DTS data - flowing well.
Figure 8. DTS differential data.
Figure 7. PLATO production profile.
technologies, including water hammer tools or lubricants – pumping fluids into the wellbore could have affected well production and hence would not provide a noninvasive production survey.
As predicted by the tubing force analysis, the coiled tubing friction locked about 139 m short of the target depth. The DTS survey was conducted despite not making it to the toe of the well, only two frack ports were below the DTS string. Flow from ports one, two, and three would be considered ‘from below’ and not be evaluated in the survey.
DTS survey operation summary – 36 hours start to finish Ì Day 1
h 23:20: Shut in well, run in hole with coiled tubing.
Ì Day 2 h 03:50: Coil frictioned out at 3450 mKB (target depth was 3589
m), Begin DTS survey.
Ì 07:00 Start producing well. h 16:10: Shut in well (14 hour warm back survey begins).
Ì Day 3 h 06:10: DTS survey complete, pull out of hole. h 12:30: Job complete, well put back on production.
The flow rate during the DTS survey varied from 140 - 195 e3 m/d. during the production portion of the DTS survey as displayed in Figure 5.
Raw dataThe raw DTS data shown on the right side of Figure 6 reveals some interesting trends. It was clear that some frack intervals were producing considerably more than the others. Like other wells that have been production profiled with DTS, the well did not have homogenous production along the lateral.
Data processingThe DTS data was processed using PLATO software. The software utilises a thermal mass flow model to evaluate production based on temperature changes resulting from the JT effect while flowing the well. Plato model inputs include total well production, reservoir temperature, fluid properties, and the thermal and physical properties of the tubulars present in the well.
Production profileThe production profile calculated by PLATO (Figures 7 and 8) showed that the top 11 of the 26 zones produced nearly 70% of the well’s production. Five zones; Stage 24, 23, 21, 17, and 16 produced nearly 50% of the well’s net production as shown in Table 2.
ConclusionsFibre-optic cable deployed inside coiled tubing can be used as a sensor for distributed temperature sensing when deployed temporarily into a wellbore. Distributed temperature sensing can be used to determine the production profile of a horizontal well.
On this particular well, nearly 50% of the production came from five of the 26 frack stages. The upper 11 frack stages accounted for nearly 70% of the well’s production despite little expected reservoir heterogeneity or changes to fracture design.
The packer between stages 22 and 21 appears to be the site of much of the production from these intervals. The production within stage 17 appears to be skewed towards stage 16.
There are no clear correlation between expected reservoir quality indicators and production results. DTS is cost-effective; a typical survey costs about the same as a PL survey.
