A wireless retrofit solution for replacing permanent downhole gauges

The North Sea’s Troll field, 80 km northwest of Bergen, is Norway’s largest gas reservoir. The field has been onstream since 1996, and production is expected to continue for many decades. However, declining pressure means surface compression is required to drive production, and an accurate understanding of reservoir pressure and decline is critical for meeting contractual gas deliveries and recovery targets. As an alternative option to retrofit permanent downhole gauges, the operator, Statoil, was seeking intervention-based solutions to enable data collection, if permanent gauges were not available.

Today, thousands of wells use downhole pressure gauges to optimize production and provide data, which are used to maximize recovery. As the lifetime of producing wells may extend past the practical service life of these gauges, intervention-based solutions can provide an effective alternative. Proving, evaluating and continually enhancing this technology will result in more robust systems, greater service life and increased data quality, thereby enabling the benefits to be realized in a wider range of applications.

Fig. 1. The wireless gauge assembly can be installed in an existing production well.

There are 39 gas-producing wells in Troll-A. Given the extended life of these wells, permanent monitoring solutions do not offer the required longevity, and alternative intervention-based options are being trialed and evaluated.

Well 3 1/6-A-35 was completed in 1996 with a gravel-packed lower completion and a 7 5/8 × 7-in. 13% Cr upper completion. A permanent downhole gauge was not included in the upper completion.

To provide a solution, a wireless gauge (Fig. 1), with a pressure pulse telemetry system was selected, as this technique is ideally suited to retrofit applications, requiring only a low-complexity intervention, to both install and retrieve. The selected wireless gauge operates by transmitting compressed data, from a quartz pressure sensor to surface, within a pressure pulse telegram. The existing wellhead sensors can be used to detect the pulses, so no topside hardware or system integration is required.

The pressure pulse is created by choking flow at the downhole tool, until this can be detected at the surface as a small reduction in the flowing wellhead pressure. In compressible fluids, signal attenuation will occur; however, data can still be transmitted over the full well length by using a low number of longer pulses with a high-amplitude input signal.

The wireless gauge is deployed on a conventional wireline-retrievable plug or lock mandrel, so that it hangs within the production tubing. Under normal flowing conditions, the produced fluid passes up the annulus, between the wireless gauge and production tubing, until it enters the gauge through a series of ports at the top of the tool. Well pressure and temperature data, from the quartz transducer, are monitored constantly to detect well events, such as a shut-in and the re-start of production/injection.

Fig. 2. Pulse generation through position hold vs. pressure regulation.

If flowing conditions are detected at the start time for the telegram, the gauge will transmit a single pressure and temperature data point, along with information on the source of the data (shut-in or flowing condition), by creating six pressure pulses that are detected with the wellhead sensors.

To create a pulse, a pressure reading is recorded, and the choke plug is moved into the choke cage, reducing the flow area and inducing a pressure drop. The choke plug position will be held for 5 min. before the choke plug is allowed to retract. The hydraulic actuator does not hold pressure and, as this bleeds off, spring force is used to return the piston to the flowing position.

A problem for Troll A-35 was that the operating conditions of the well varied throughout the year; the same choke position was not always optimum for sending a signal to surface that was adequate for detection. Sometimes, the well might even be in a condition, where the pulse is not detectable.

To address this concern, a method of creating a pulse, using pressure regulation, was developed. Prior to a pulse, the pressure is measured, and the gauge chokes until a chosen pressure drop is reached. If the pressure drop is not achievable, the gauge goes to a maximum default position, to prevent the well from being entirely closed in. This was programmed to be 5% for the installation, Fig. 2.

Fig. 3. The results of the second test sweep (left), and the first daily telegram that followed with the 1.5-bar DHΔP setting (right).

When regulating on pressure, the choke valve will automatically adapt to any changes in production rate, as it will always try to maintain the pre-programmed pressure drop. This ensures a stable topside response throughout the installation, and ensures that the data sent to surface will be detectable.

WELL OPERATIONS, EQUIPMENT PERFORMANCE

The wireless gauge was fitted into the well with two sulfuryl chloride lithium-oxyhalide battery units and tested, on surface, prior to installation. The first operation performed by the gauge was a pulse test sweep, and a sequence of pre-programmed pulses, with different amplitudes, was sent.

Fig. 4. Transient flow modelling results for a 7.5-bar pulse at the tool.

A short sweep of 0.5, 1.0 and 1.5 bar DHΔP was used to test the new gauge program. Observation of the third pulse on the sweep showed a clear signal, indicating that 1.5 bar downhole pressure drop, was adequate for the daily telegrams. Figure 3 shows this second test sweep, and the first daily telegram that followed with the 1.5-bar DHΔP setting.

TRANSIENT RESPONSE

Before a gauge is installed, the feasibility of communication within the well is confirmed, and the size of the downhole pulse is determined, by modeling the well, using transient multi-phase simulation software. The aim of the software simulation is to determine the required downhole pressure drop, and determine whether the well is stable when attempting to achieve the required pulse size.

A choke valve placed in the planned location of the gauge was simulated to choke to a near-closed position for 2 min. The  simulation showed a baseline pulse size on surface of 2.5 bar achieved, with a pressure drop downhole of 7.5 bar, Fig. 4.

The simulation was then run multiple times, at different choke positions, to determine which downhole pressure drop would give the required 1 bar pressure on the surface. This was simulated to be 5 bar, Fig. 5. As well as this, multiple pulses were simulated together, to determine minimal time between pulses to allow production to stabilize. A 10 min. gap was chosen from this for the test sweep.

Fig. 5. Transient flow simulation results showing production stabilization between pulses with 5-bar DHΔP

When comparing the model to the actual test sweep results, there was reasonable correlation. The results of the simulation were reviewed only from the perspective of pulse generation and resulting flowing pressure transients, but the close match between modelled and actual data proved the feasibility of using transient simulation software for confirming the telemetry prior to running the gauge.

POST PROJECT OBSERVATIONS

The wireless gauge sent its last data telegram 428 days after it was installed. The initial battery calculation indicated that the tool would function for 347 days, based on the assumption of one telegram being sent every day. Since the well temperature was low, the self-discharge of the batteries was minimal, and the telegram actuation dominated tool life. The wireless gauge transmitted 354 telegrams and eventual battery depletion was considered the most likely cause for the cessation of telegrams. The wireless gauge remained in the well, in the fully open position, for a further three months, until being retrieved on slick-line.

A review of the tool diagnostics data and function testing on laboratory power confirmed that the tool remained fully operational, and that the batteries had discharged in service. 

DATA REVIEW

Data interpretation was performed on a weekly basis through remote access to the operator’s data management system. The start time for each pulse was manually picked from the tag for the wellhead transducers and entered into an interpretation program. The resultant data were plotted, and the results provided to the operator.

The wireless gauge provides downhole data for both flowing and shut-in conditions. For flowing conditions, the wireless gauge logs a reading from the quartz sensor immediately prior to sending the data telegram. For shut-in conditions, as pressure pulses can only be created in a flowing well, the tool remains dormant but monitors well pressure. Once flowing conditions are recognized again, the highest pressure detected during the shut-in period will be logged and transmitted.

Fig. 6. Plot showing transmitted and recorded downhole pressure, and temperature data.

The transmitted data point is also stored to the tool memory, and it can be retrieved once the tool is pulled. In all, 427 data points were recorded during the tool’s operation: 330 were transmitted successfully to surface; 61 were not transmitted, due to a detected well shut-in; 24 of these were lost during transmission; and 11 were recorded by the tool after the battery power was too low for telegram transmission. Figure 6 shows a plot of the wireless transmitted data, and data recovered from the tool memory.

Real-time well data are stored at a high frequency within a web-driven data storage and management system, from all well transducers field-wide, both at surface and downhole. The volume and format of the data allow for them to be processed readily to quantify well performance, monitor trends and detect anomalies. Conversely, data from the wireless gauge was provided in pseudo-real time, at a low frequency.

CONCLUSIONS

The installation of the wireless gauge demonstrated that the technology can be used in an existing production well, and that it can transmit data successfully over a range of operating conditions in a gas well. The use of existing wellhead sensors, to detect the pulse telegram, resulted in a low-complexity system with minimal downhole hardware and, more significantly, no requirement to modify the topside systems to provide access to the data.

The modelling and preparation for installation were representative of results observed during service. Rigsite operations were carried out without incident and in accordance with standard operating procedures. The tool proved robust and reliable, and delivered data in line with expectations for the device. All key objectives for the trial were met.

Fundamentally, the technology is simple and efficient to install, and the data are easy to obtain and use alongside other data. There were, however, a number of areas of the operation that have since been improved through technological developments.

Although transient multi-phase modeling has been shown to adequately reflect well conditions, additional factors in well performance, or paucity of information during the planning phase, can make optimum programming ahead of installation a challenge. To avoid the need for recovery and reprogramming, a “pulse selection” feature has been added to the tool, utilizing the shut-in detection feature to select a pulse from the pulse sweep. The pulse size from the test sweep is selected by implementing surface-to-downhole communication. The well is choked on the surface at a certain time after the test sweep. The time window, in which this choke takes place, selects which pulse from the test sweep to use for daily telegrams. As long as the test sweep contains a usable pressure drop, there should be no need for a pull and reprogramming. Trials are ongoing with semi-duplex telemetry, to allow reprogramming of the device at any time during its service life.

The data telegrams from the wireless gauge were readily detectable in the surface transducers, with a 0.3-bar pulse sufficient. No data were lost, due to indistinct pulses or misinterpretation of a well event. The comparison of the transmitted and recorded data confirmed the correct interpretation in all cases. The manual interpretation of data was a valuable process in this early installation, as it allowed data quality to the reviewed in an ongoing basis against a changing set of variables. Interpretation software has since been developed that can access the wellhead transducers, perform the interpretation and deliver the results to the operator’s data storage system. A log of the interpretation is still recorded for quality control purposes, with a user interface for diagnostic purposes.

The memory capacity, in the wireless gauge deployed in the Troll well, was sufficient to record the transmitted data points and tool diagnostic data during pulse generation on a daily basis. The transmitted data provided reservoir information for flowing and shut-in conditions for steady-state analysis. The tool uses a high-resolution quartz sensor and is programmed to detect well shut-in; memory capacity in the tool has been increased to allow these full-pressure build-up data to be recorded, with sufficient capacity for several years.

The recovered wireless gauge suffered no appreciable wear or degradation of performance after more than a year in service, but it was unable to continue to function, due to depletion of its primary power supply. The efficiency of the wireless gauge has been improved to effectively double the service life for the well: further improvements will be achieved with downhole power generation.

The installation of a wireless pressure gauge in Well A-35 at Troll A has demonstrated that the technology can be applied in an offshore producer well. The process of installation is straightforward, and it has been proven that data can be transmitted to surface using pressure pulses. It also has been demonstrated that the device was working, as intended. 

Wireless technologies have enjoyed great success over the last decade in drilling and well test applications, and the benefits of cableless communication in completion applications can be illustrated readily. Building a track record of successful installations, learning the lessons of early projects and implementing improvements to the technology are fundamental steps to establishing its value to operators and gaining acceptance. Using retrofit-capable, slow-pulse wireless technology provides the unique opportunity for relatively low-risk applications to meet a need for in-well monitoring, and prove the technology for use in intelligent well applications in the future.   

ACKNOWLEDGMENT

The authors are grateful to the Troll license partners (Petoro, Shell, Total, ConocoPhillips and Statoil) and Tendeka for allowing this work to be published.

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