New ‘real-time’ technology expands convenience, flexibility and fidelity of powerful well system diagnostics for oilfield customers TGT announced today the release of its real-time Indigo platform, significantly expanding the range of benefits brought by its family of powerful through-barrier diagnostic systems. The new real-time technology enables well data to be viewed and analysed at surface during the execution of well diagnostic programmes without compromising on measurement fidelity. This will bring several benefits to customers, including improved data quality, enhanced intervention efficiency and faster remediation decisions.   Ken Feather, TGT’s Chief Marketing Officer commented, “Real-time data isn’t new to the oil industry, but currently available transmission systems couldn’t meet our exacting data quality standards—so we developed and built our own high-fidelity system. In doing that we have taken conveyance and decision-making flexibility to an entirely new level for our customers, with no compromise on measurement quality. As a result, we expect the popularity of our diagnostic systems and products to expand even further.”   TGT creates all its own hardware and software in-house and follows a strict philosophy of ‘fidelity’ in the design and manufacturing of its diagnostic sensor technology and instruments. This philosophy is clearly embodied in its ‘Indigo’ platform of complementary sensors and auxiliary equipment. Indigo technology is distinctly ‘low noise’ and custom-built to operate perfectly with TGT’s through-barrier suite. The new real-time capability is particularly relevant to TGT’s acoustic-based ‘spectral’ and electromagnetic-based ‘EmPulse’ diagnostic systems, which lead the industry in diagnosing flow and integrity dynamics within oil and gas wells, helping operators to improve well performance.   Traditionally, through-barrier diagnostics are performed using ‘memory-mode’ deployment. With a track record of 20-years and an efficiency of more than 99%, TGT’s memory-mode deployment remains a flexible and popular choice across the industry. With this approach, diagnostic information is accessed when the measuring instrument is retrieved from the well. However, with real-time access, data can be viewed during the diagnostic intervention and streamed remotely from the wellsite enabling a host of benefits, such as dynamically adjusting the acquisition program, and making faster decisions.   Artem Buharaev, TGT’s head of Indigo development also commented, “We have overcome many technical challenges in commercialising our real-time Indigo platform. Existing data transmission technology available within our industry generates unacceptable levels of acoustic and electromagnetic [EM] ‘noise’, that would otherwise degrade our highly-sensitive sound-based and EM-based measurements, so we developed our own design that was both ‘quiet’ and fast.”   The real-time system comprises of a downhole Indigo modem module and a surface interface unit that enables two-way communication between surface recording equipment and the downhole instruments. Testing Indigo's 'high fidelity' platformReal-time Indigo platform structure Indigo is a fully integrated ‘high-fidelity’ platform of wellbore production sensors, communication, navigation, memory and power supply modules that are designed to work seamlessly with TGT’s flagship through-barrier diagnostic systems. Engineered and built completely in-house, all Indigo modules have been designed to eliminate the possibility of interference with TGT’s high-performance acoustic and electromagnetic sensors. Conventional industry wellbore instruments contain components and circuitry that generate rogue acoustic and electromagnetic [EM] noise that can interfere with measurements, effectively compromising the data analysis. Our customers rely on the fidelity of our diagnostic insights, so it’s important that our measurements only capture true well system behaviour, which is why we developed Indigo.   Indigo enables both memory-mode and real-time data acquisition from production sensors housed in titanium. Measurements include high-precision temperature, pressure, gamma ray, casing collar locator, fluid capacitance, fluid resistivity and heat-exchange. Fullbore and continuous flow spinner modules are added to provide complete wellbore flow diagnostics.

Challenge The operator of this North African oil producer was planning a workover to replace a leaking production string. As part of the work process, the client wanted to locate and eliminate the sustained annulus pressure (SAP) in the B-annulus between the 7-in. and 9⅝-in. casings. SAP indicates an underlying integrity problem. In this case, pressure was building to approximately 100 psi over a period of 10 hours, indicating a progressive annular leak that could become worse over time.   Accessing the B-annulus and making repairs, such as cement squeeze operations, is much easier when the tubing has been removed. The main challenge was accurately identifying the leak source and flow path associated with the SAP. Conventional temperature measurements can indicate flow behind casing but they lack precision, especially when the source is in an outer annulus and the sensor is located inside the tubing. Accurately determining the source of the SAP would be the first step to planning and implementing a successful remediation. Multi Seal Integrity example well sketch. Multi Seal Integrity evaluates the seal performance of multiple barriers, locating leaks and flowpaths throughout the well system, from the wellbore to the outer annuli. Delivered by our True Integrity system with Chorus, Indigo and Maxim technology, Multi Seal provides a clear diagnosis of leaks and rogue flow paths so the right corrective action can be taken. Multi Seal is used in a targeted fashion to investigate a known integrity breach anywhere in the well system. Barriers can also be validated proactively to confirm integrity. Either way, Multi Seal provides the insights needed to restore or maintain a secure well. Solution The operator selected TGT’s Multi Seal Integrity solution to evaluate the well and locate the source of B-annulus pressure. TGT engineers and analysts used the True Integrity system to locate leaks and validate seals throughout the well.   The True Integrity system combines Chorus acoustic sensing and analysis technology with high-precision temperature surveys provided by Indigo. The Chorus Acoustic Power Spectrum (APS) can reveal flow activity in and around the well system, particularly fluid flow through restrictions or between zones that have high differential pressure. For example, it can identify fluid movement into or out of permeable formations and characterise fluid movement within the well completion.   The well was surveyed under both shut-in and B-annulus bleed-off conditions. The survey was designed to reveal flow dynamics and fluid flow occurring in the B-annulus, which would identify the source of SAP along the wellbore and the flow paths between active formations and the B-annulus. Multi Seal Integrity diagnostics located the source and traced the flow path of the fluid that was causing sustained pressure in the B-annulus. Result The Chorus APS revealed flow activity opposite the perforations during the shut-in survey. This suggested the presence of active crossflow in the formation layers at that depth. The Indigo temperature survey also confirmed flow activity at the depth of the target reservoir during the shut-in survey.   During the B-annulus bleed-off survey, additional flow was observed from the target reservoir towards the surface. The low-frequency content of this acoustic signal is characteristic of cement channel flow (Figure 1). The Multi Seal Integrity survey identified the source of the SAP as the target reservoir, with the flow path extending through cement channels in the B-annulus.   Using this information, the operator was able to conduct an effective cement repair and recomplete the well, bringing it back to safe, clean and productive operation.

Challenge A high gas–oil ratio leads to unnecessarily high carbon emissions, lower oil production and increased carbon-per-barrel rates. Managing and processing excess gas requires substantial energy and capital expenditure for surface infrastructure and facilities. In this case, the aim was to identify zones for gas shut-off that would enable the operator to optimise surface infrastructure capacity, maximise oil production and minimise carbon footprint.   Well A-1 features a 7 in. x 4-1/2 in. cemented liner across several commingled oil and gas-bearing zones. Developing compartmentalised multi-stacked reservoirs using simplified well completions makes it challenging for diagnostics to determine production allocation, reveal flow assurance issues, understand reservoir connectivity, monitor individual well performance, and forecast total field production.   Gas production had already exceeded the limit of surface processing facilities for well operation with existing production rates, which meant the operator had to choke back production. In addition, the unwanted gas was taking up part of the operator’s pipeline quota and creating other transportation and flow assurance issues. The well contains at least five clastic reservoir zones, each with multiple layers, that are perforated across an interval of more than 1,500 ft. This level of complexity meant that conventional production logging tools were unable to adequately characterise flow or confidently distinguish the main gas-contributing layers. Total Flow example well sketch. Total Flow locates and quantifies wellbore and reservoir flow, and reveals the relationship between the two. Delivered by our True Flow system with Chorus and Cascade technology, Total Flow provides the clarity and insight needed to manage well system performance more effectively. Total Flow is commonly used to diagnose unexpected or undesirable well system behavior, but it can also be used proactively to ensure the well system is working properly. Solution The operator selected TGT’s Total Flow product, with Cascade, Chorus and Indigo as the main technology platforms chosen to perform the well system diagnostic survey. This would reveal which zones were contributing to the production of oil and gas, diagnose wellbore and reservoir flows, and help identify potential well integrity issues such as annulus sealing problems due to poor cement. The solution combines the sensitive, fast-response temperature sensor of the Indigo platform with high-definition acoustic sensing from Chorus that reveals active flow in the well system.   Comprehensive temperature and flow modelling with Cascade enabled TGT analysts to assess and allocate production distribution and provide accurate oil and gas flow profiles across the reservoir zones. The survey also identified active flow layers and recorded characteristic acoustic signals generated by liquid and gas flowing through reservoir media and the wellbore. Pre- and post-workover survey results illustrate the effectiveness of the gas zone isolation programme and resulting decrease of gas production, which enabled surface infrastructure to stay within its operating envelope. Result Total Flow diagnostics quantified the contribution of reservoir layers from five different zones and identified the main gas producing layers, providing a comprehensive flow profile. The operator was able to define active flow units and differentiate between flows through the reservoir matrix, the behind-casing channels and the wellbore completion components.   This enabled the operator to target and conduct an effective remediation plan. The workover involved a 200-ft-long 2-⅞- in. straddle installed to isolate the zone with the highest gas contribution. A post-workover Total Flow survey was conducted to evaluate the effectiveness of the isolation job. The straddle had isolated 83% of the gas production. This delivered a reduction of 7.9 MMscf per day at surface (equivalent to 2.8 Bscf per year).   Overall, the isolation job was considered highly successful. Identifying the main gas shut-off zones played a crucial role in optimising surface infrastructure, maximising oil production, and minimising carbon footprint for this well.

Challenge A routine field survey discovered gas bubbling in the cellar of the subject well, right behind the conductor. None of the annuli in the well exhibited sustained pressure, complicating the task of locating the source and flowpath of the gas. The operator needed reliable diagnostic information to plan and target a remedial workover.   Analysis of cement bond and variable density logs (CBL/VDL) indicated a very poor cement bond behind the 9⅝ in. casing and, in the 9⅝ in. × 13⅜ in. pipe section overlap, there was no cement at all. After performing a pressure test of the annular space between the production tubing and the casing, and analysing samples of the bubbling gas, it was determined that the gas was coming from both the producing formation and a shallower formation. Multi Seal Integrity example well sketch. Multi Seal Integrity evaluates the seal performance of multiple barriers, locating leaks and flowpaths throughout the well system, from the wellbore to the outer annuli. Delivered by our True Integrity system with Chorus technology, Multi Seal provides a clear diagnosis of leaks and rogue flow paths so the right corrective action can be taken. Multi Seal is used in a targeted fashion to investigate a known integrity breach anywhere in the well system. Barriers can also be validated proactively to confirm integrity. Either way, Multi Seal provides the insights needed to restore or maintain a secure well. Solution The operator selected TGT’s Multi Seal Integrity product using the Chorus (acoustic) platform and the Indigo high-precision temperature modules to perform a leak detection survey that would reveal both the source and the flowpath of the gas bubbling at surface.   In contrast to traditional production logging methods, the Chorus acoustic system can identify minor fluid or gas migration behind multiple steel and cement barriers. The system’s sensitive hydrophones can capture and characterise acoustic signatures associated with fluid flow through micro-annuli, cement channels and leaks in completions, or filtration through pores in the formation. Figure 1: The final confirmation survey (left) showed that the source of the migrating gas had been sucessfully isolated. The cellar of the well still shows signs of bubbling due to remnant gas present in the well system, but this had cleared approximately one month after the workover. Result The complex flowpath started in the active reservoir, with gas moving up behind the 9⅝ in. casing, with further contributions from two shallower formations. The gas continued up behind 9⅝ in. casing to the 13⅜ in. casing shoe, then up behind the 13⅜ in. casing and finally behind the 20 in. casing to the surface. The operator developed a remediation plan based on this detailed understanding. The accuracy of the leak determination made it possible to avoid unnecessary workover-related activities and enabled the operator to minimise nonproductive time.   Several validation surveys were deployed to assess the effectiveness of the workover operations (Figure 1). After completion of the last corrective cementing job, the final survey showed that the source of gas migration had been successfully isolated, although the cellar still showed signs of bubbling. The cause of this bubbling was that gas present in the system was still travelling through the well to reach the surface. This remnant gas left the system approximately one month after intervention, and the well showed no further signs of gas migration at surface.   TGT’s Multi Seal Integrity product enabled the field operator to identify the gas source and shut it off. Methane is 80x more potent as a greenhouse gas (GHG) than carbon dioxide and it constitutes roughly 20% of all global GHG emissions. Eliminating fugitive methane emissions from the well helped to restore integrity and reduce the carbon intensity of energy production.

Challenge High water cut in producing wells leads to unnecessarily high carbon dioxide emissions and increased carbon-per-barrel rates. Managing, treating, and reinjecting or disposing of excess water requires large amounts of energy, making water cut reduction a key area for performance improvement. Well OP-1 was completed in 1971 as a vertical oil producer and it features a large number of perforated zones from numerous campaigns over the course of its operational history. The oil production rate was approximately 100 bpd, which was considered uneconomic, and the operators decided to switch the completion zone to boost production and enhance recovery from the field.   Following a workover in December 2018, the well was put back on production from the new completion zone (B2), but unexpected water production was observed. The total liquid rate was more than twice the projected level and the water cut was about 80%. The production gas–oil ratio at the separator was lower than expected when compared with a PVT analysis of the B2 zone in a nearby well. Furthermore, water analysis results for well OP-1 were close to the existing results from other completion zones, which indicated substantial water entry from an unknown source. Figure 1: Pre-workover diagnostics survey reveals that the main source of water is non- perforated water-bearing Zone B1. Solution Conventional production logging tools such as spinner and multiphase sensors can provide a production profile inside the wellbore, but cannot identify behind-casing communication with water-bearing formations or crossflow.   The field operator selected TGT’s Total Flow diagnostics to determine whether behind-casing crossflow was the cause of high water cut in well OP-1 and to locate the water source. The combination of TGT’s Chorus spectral acoustic survey with standard production logging tools enabled the survey team to identify behind-casing flow (Figure 1). TGT’s Indigo and Cascade technology was also used to quantify the low flow rates. Figure 2: Post-workover survey confirms the effectiveness of the remedial work and the elimination of water entry from Zone B1. Result Analysis of the survey results indicated that the crossflow from the previously isolated perforated zones was less than 1% of the total. About 30% of the liquid inflow was coming from the targeted perforated interval (Zone B2). The main unwanted production (approximately 69%) was coming from the non-perforated water-bearing Zone B1 and was the result of behind-casing crossflow (Figure 2). A remedial workover was conducted in September 2019 to address the crossflow issue. A cement evaluation log showed that the cement condition above the Zone B2 perforation interval was improved and a successful pressure test (3,000 psig) against Zone B2 was performed. The productive Zone B2 was stimulated once more using a revised procedure.   A flowback test conducted before the second survey showed that there had been a significant decrease in water production with time, and water cut was 0% in the post-workover survey. Both Chorus and Indigo data analysis confirmed that inflow was from only the targeted interval with no evidence of behind-casing communication with Zone B1 (Figure 3).   TGT’s True Flow enabled the field operator to identify the water source and shut it off, thereby increasing oil production, lowering carbon intensity and improving well economics