Production logging is an essential resource for managing well and reservoir performance, but traditional methods only see half the picture. In this article, we look at a new approach that looks further to reveal the true flow picture. Article featured in Harts E&P   The last few decades have brought impressive advances in ‘production logging’ technology, especially in the context of new sensor designs and diagnosing complex flow downhole. Fibre optics are also playing an increasing role in production surveillance. However, the fundamental technique of using wellbore-confined production logging tools (PLT’s) to infer total well and reservoir flow performance still dominates the industry.   Basically, PLT measurements are used to monitor fluid properties and flow dynamics in the wellbore and importantly, to determine production and injection ‘flow profiles’ where fluids enter or exit the wellbore, such as via perforations or inflow control devices. These measured and calculated flow profiles are used to assess the production and injection performance of the entire well system.   However, the validity and accuracy of this approach depends on many factors, and chief amongst them is the ‘integrity of communication’ between the wellbore and reservoir formations at the entry/exit points. Analysts and operators using PLT’s must assume that fluids entering or exiting the wellbore are flowing radially from or to the formations directly behind the entry/exit points. And unfortunately, this is often not the case. Flowpaths can exist through annular cement channels, formation packers or natural fissures, and fluid will always find the path of least resistance. From a compliance, environmental and performance perspective, these unwanted flowpaths are bad news. Decisions made assuming wellbore flow correlates directly to target reservoir flow can lead to complex reservoir and field management issues, and compromised asset performance. From a diagnostics perspective, it’s clear that analysts and operators can’t rely on PLT’s alone to diagnose and manage well system performance – a more powerful diagnostic approach is needed. Seeing further The challenge of behind-casing ‘cross-flow’ is not new and the industry has made several attempts over the decades to diagnose this insidious phenomenon. Some of the early techniques used nuclear activation, chemical tracers and noise logging to try to detect and map flow behind pipe, but these methods generally lacked the precision demanded of modern-day diagnostics and were, at best, qualitative. However, fueled by an increased operator focus on compliance, the need for better asset performance, and pure ingenuity, a new diagnostic capability has emerged that is rapidly becoming the new industry standard for diagnosing flow downhole. True Flow system Understanding the dynamics and connectivity of wellbore and reservoir flow downhole with any degree of precision and accuracy is a highly complex task that extends beyond the capabilities of conventional ‘logging’.   Which is why ‘True Flow diagnostics’ utilises a more powerful ‘system-based’ approach. The True Flow system combines experience and expertise with proprietary technology and an industry proven workflow to deliver a more complete picture of well system flow dynamics, and enable better informed well, reservoir and field management decisions (Figure 1). Programmes and methods The first ingredient and stage in the workflow is ‘Programmes & methods’. Following an initial customer consultation, analysis of well performance history, completion design, reservoir and fluid properties and assessment of diagnostic objectives, analysts customise a survey programme that will effectively ‘stress-test’ the well system to expose its flow dynamics in a number of scenarios. This can be likened to a heart specialist exercising a patient on different treadmill settings whilst scanning physiological parameters such as heart-rate, blood pressure and electro-cardio signals. Typical programmes will include a precisely-timed sequence of flowing and non-flowing surveys that allow the entire well system to warm-up and cool-down between surveys. Tools and measurements The second stage and ingredient is the application of high-fidelity ‘Tools & measurements’ by engineers that survey the well according to the diagnostic programme. The measurements come from basic and advanced PLT-type wellbore probes, and a combination of proprietary acoustic and high-precision temperature sensors. Fluids flowing throughout the well system generate acoustic signals encoded with flow information. The acoustic sensing technology used by the True Flow system captures this information in the form of sound pressure across a wide frequency and amplitude range. Importantly, the remarkable dynamic range of this technology means it can sample absolute sound levels from deafeningly loud to imperceptibly quiet without losing clarity or detail. This means that a wide variety of flow scenarios can be located and characterised throughout the well system, from the wellbore to several metres into the reservoir formation. The temperature sensor in itself is unremarkable, being an industry standard fast-response, high-precision type capable of resolving to decimals of degrees. However, correlating temperature changes observed during the diagnostic programme and combining it with the acoustic data, wellbore flow measurements and other well and reservoir information is the key to quantifying flow by the next ingredient of the system – ‘Processing & modeling’. Processing and modeling During the processing and modeling stage, data acquired during the survey programme are enhanced further by analysts using a proprietary digital workspace and a number of processing and modeling ‘plug-ins’. High-resolution acoustic data are transformed into an ‘Acoustic Power Spectrum’ to reveal the characteristic signatures of different types of flow. Analysts can select from a catalogue of digitally enhanced spectra to illuminate particular aspects of the flow and extract maximum information from the acoustic signals.   The subsequent flow modeling is integral to the entire True Flow system and represents another significant advancement in flow diagnostics. Precision temperature measurements acquired during all stages of the diagnostic programme are assimilated together with all other data to derive ‘reservoir flow profiles’. These are distinct from conventional PLT-derived wellbore flow profiles because they quantify flow exiting or entering formation layers whether or not casing or perforations are present. Built on more than a decade of R&E and commercially proven in thousands of wells, the flow modeling engine solves complex thermohydrodynamic physics by matching simulated and measured temperature and other responses in the flow scenarios created during the diagnostic programme. The result is ‘quantified reservoir flow’ that together with wellbore flow measurements complete the total flow picture. Analysis and interpretation The previous True Flow stages are curated under the watchful eye of analysts who also administer the final important stage of the workflow – ‘Analysis & interpretation’. Armed with all available well data, processed and modeled results, and an expert knowledge of true flow applications, the analyst will derive and compile the diagnostic result. Whilst more complex scenarios can take a number of days to complete, the final result is a more comprehensive and accurate diagnostic of reservoir and wellbore flow that ultimately leads to better well management decisions and improved asset performance.   The True Flow system is used to provide a range of diagnostic answer products that address most flow-related applications. These products include ‘Total Flow’, which combines both wellbore and reservoir flow (Figure 2), ‘Sand Flow’ for sand management applications, ‘Fracture Flow’ to optimise fracturing programmes, ‘Stimulate Flow’, ‘Horizontal Flow’, and many more. FIGURE 2. A typical Total Flow answer product derived using the True Flow system is depicted. The PLT-derived wellbore flow profile (left) shows oil and water entering the wellbore at P2 only, suggesting the source of production is from the target reservoir at the same depth. However, the True Flow system reveals that several other formation layers are contributing to this flow, including that the main oil production is coming from the upper and lower sections of the A1 formation, and the water is emanating from deeper layers. By seeing the total flow picture, the operator has a more accurate and complete understanding of well and reservoir behavior and is able to target appropriate remediation. A bright future The old thinking cannot answer today’s new challenges. As well systems become more complex and older, managing performance will remain a priority and continue to task the industry. Wells are built to connect the right fluids to the right places, safely and productively, but forces, materials and age conspire to undermine this perfect balance. Traditional production logging will continue to play an important role in managing production, but it’s clear that we need to look beyond the wellbore, to the reservoir itself, in order to see the true picture.

Article featured in Oilfield technology   Well integrity management is a full lifecycle process adopted from the well design and construction phase right through to abandonment.   Yet, just as well diagnostics should take place at the outset of the well life – with even new completions sometimes containing flaws such as leaking connections and poor cement isolation – there is an increased focus today on routine integrity management, as well systems age and move towards abandonment. Revitalising aging wells In many regions of the world, increasing demands are being placed upon ageing well stock as operators seek to extend field life. Significant remaining reserves are the prize and technology-enabled process innovations, such as drilling multi-lateral extensions from existing wells, allow this to happen.   In the Middle East, for example, more than 70% of the ~800 Middle East platforms and associated well-stock are more than 25 years old, and in the North Sea, according to the UK Oil & Gas Authority, there remain 20 billion barrels of oil and gas resources still to be recovered on the UK Continental Shelf – a region that has been continually developed for nearly 50 years.   In such cases, whilst multi-lateral well components are new, the original wellhead, conductor and production casings have remained the same.   However, whereas previously such well stock survived through regular maintenance of the more accessible elements of the well, today more powerful well integrity diagnostics are required to monitor casing strings, tubulars and other crucial well components throughout the well system – from inside the tubing.   This article will look at how this is being achieved with through-barrier diagnostics. Through-barrier diagnostics Through-barrier diagnostics, a capability developed and perfected by TGT since it was founded two decades ago, is a valuable resource in proactive integrity management today because it evaluates critical aspects of the entire well system from inside the tubing.   Through-barrier diagnostic systems can sense dynamic well behavior and properties throughout the well, helping operators to evaluate the condition and performance of critical well components from inside the tubing.   By cleverly harnessing heat, acoustic and electromagnetic [EM] energy, through-barrier diagnostics can determine the wall thickness of individual tubulars, and locate and quantify fluid movements behind the pipe.   Two key areas where through-barrier diagnostics are having a major impact today are in tracking corrosion and sustained annulus pressure [SAP]. Tackling corrosion in the rise of chrome In some regions, downhole conditions are highly corrosive and well completions are constantly under attack from aggressive fluids, such as hydrogen sulphide, carbon dioxide and chloride. The degradation of wellbore tubulars and metal barriers is a major threat to well integrity.   On the Arabian Peninsula for example, formations such as Rus, Simsima, and Daman can cause severe corrosion of the outer well casing strings. Corrosive fluids from the aquifers can reach the outer casing surface because of integrity breaches in the outer well annulus. This is because either the outer cement sheath has degraded over time, or the initial cementing operation may have been compromised by the inability of formations to support pressure, resulting in cement losses and an imperfect seal.   In such cases, comprehensive and regular inspection is required by operators to determine whether corrosion is taking place at an acceptable rate, or if intervention and remedial action is required. To this end, the well diagnostics approach must provide quantitative information about multiple casing strings efficiently and reliably.   Yet, previously few operators were able to track corrosion to this level of detail and across all pipe strings.   To address this challenge, TGT has developed EmPulse® – a multi-barrier pipe inspection system capable of providing barrier-by-barrier visualisation of the tubulars that make up the well operating envelope, reliably and proactively. Ultra-fast EM-based sensor technology and time-domain measurements, coupled with advanced Maxwell processing, enable the system to quantify metal loss in up to four barriers independently and accurately.   In this way, it delivers sensitive and fast response measurements, bringing with it significant advantages over the frequency-based measurements offered by ordinary pipe inspection systems. Frequency-based measurements are also unable to distinguish the thickness of individual barriers and as a result provide limited information about barrier condition or the precise location of failures.   Another challenge EmPulse is addressing is that of chrome.   In a bid to pre-empt corrosion, many operators are opting for alternative steels and corrosion resistant materials, such as chrome, nickel and molybdenum. However, such materials pose even more challenges to ordinary pipe inspection systems with the decrease in ferrous content causing EM signals to decay too quickly for an effective measurement.   Yet, recent deployments in the Middle East have shown that EmPulse can again quantitatively determine the individual tubular thickness of up to four concentric barriers, even when there are high amounts of chrome in the tubulars.   In one Middle East operator-witnessed ‘yard test’ consisting of a 28% chrome pipe with built-in mechanical defects, the high-speed EM sensor technology within the EmPulse system correctly identified the man-made problems in a controlled environment.   Additional operations took place in two live Middle East wells in a very high hydrogen sulphide gas production scenario with 28% chrome tubulars. In this case, the EmPulse system again functioned as planned, and recorded the status of three concentric well barriers. A multi-finger caliper recording also confirmed the electromagnetic results for the condition of the inner pipe.   As operators endeavor to protect well integrity in challenging production environments and require versatility over tubular materials, it’s good to see that through-barrier diagnostics – backed up by many of the industry’s leading well log analysts – are meeting these challenges and providing a complete end-to-end well diagnostics solutions. Cementing and sustained annulus pressure (SAP) Two other challenges to well integrity today – both interlinked – are that of well cementing and sustained annulus pressure [SAP].   As operators look to deeper and longer reach wells, cementing techniques and sealing abilities have been pushed to the limit. According to the Society of Petroleum Engineers [SPE], at least 25-30% of wells are estimated to have annular pressure problems with cementing being one of the root causes. One outcome of this is SAP – pressure in any well annulus that rebuilds when bled down.   SAP is often the result of weaknesses in the cement during completion; or cement degradation due to thermal and pressure loading; leaking tubing connections or wellhead seals; and corrosion. According to a 2013 SPE webinar on wellbore integrity [Paul Hopmans], out of ~1.8 million wells worldwide, a staggering 35% have SAP.   So how can well cementing and SAP be addressed?   To date, conventional means of tracking poor cementing and SAP is through surface measurements, such as fluid sampling, bleed-off/build-up data and downhole measurements such as ‘cement bond logs’, temperature and ordinary noise logs. This, however, only provides limited information and may be unable to locate leaks and unwanted flowpaths behind multiple barriers – especially when the leak rate is low.   To address this information gap, TGT’s ‘spectral diagnostics’ technology tracks fluid movement behind pipes from within several casing strings. This is achieved using high-fidelity downhole sound analysis systems to capture the frequency and amplitude of acoustic energy generated by liquids or gas moving through integrity breaches and restrictions. Complementing this, spectral diagnostic systems utilise high-precision temperature measurements to help locate integrity breaches throughout the well system.   While conventional production logging measurements typically assess only high-rate first-barrier failures – the high-fidelity recording, sensitivity and clarity of spectral diagnostics enables the tracking of even low-rate leaks at very early stages behind multiple barriers, thereby enabling timely intervention.   In figure 2, a water injector well experienced sustained B-annulus pressure, although the build-up rate did not exceed one bar a day – indicating a low-rate leak. A cement bond survey indicated good cement bonding below X500m, and poor bonding above, likely to provide flowpaths for fluid movement behind casing.   A survey utilising TGT’s spectral diagnostics system was conducted and revealed fluid flow from the reservoir around X540m and channelling up the annulus through the incorrectly assumed ‘good bonding’ area.   The frequency spectrum pattern correlated with reservoir permeability and fluid-type profiles, suggesting gas was being produced from these formations. The operator used the information to target a cement squeeze operation at the desired location in the well – restoring B-annulus integrity and eliminating the SAP. Figure 2 – Information from spectral diagnostics in a water Injector well Spectral diagnostics to abandon wells securely Spectral diagnostics can also play an important role in ensuring that wells are properly sealed during abandonment, especially with respect to unwanted fluid flow along the outer boundaries of the well system to surface – clearly a situation the operator wants to eliminate.   Operators perform through-barrier spectral diagnostics prior to abandonment to indicate the integrity status of the entire well system, and reveal where special remediation measures need to take place to seal the well properly and permanently. Diagnostics are also performed post-abandonment to validate that there is no unwanted fluid flow taking place and that the well is secure.   The well shown in figure 3 was part of an abandonment campaign where the operator observed sustained annulus pressure building at a rate of 0.1 bars per day in the C-annulus and 5 bars per day in the B-annulus. The maximum pressures in B-annulus were 35 bars while in C-annulus it was only 3.2 bars.   Multiple survey and plug/section milling stages were executed to abandon the well and each time through-barrier spectral diagnostics aided in targeting the plug intervals and verifying the integrity of the plug.   After the third stage, the sustained annulus pressure was eliminated in both annuli and spectral data confirmed that the unwanted flow in the outer annuli had been abated. In figure 3, one can see that the acoustic frequency-amplitude spectrum seen at stages 1 and 2 reveal zones of upward gas migration behind casing. The acoustic spectrum seen after stage 3 confirm that the gas migration had been stopped [the small acoustic response is due to residual gas].   As a result, the operator could depart from the well confident that the well was totally secure. Figure 3—Spectral diagnostics were performed during the three stages of abandonment for this well, helping the operator target special remediation measures pre-abandonment and validating integrity post-abandonment. Effective diagnostics throughout the well system Well integrity is all about ensuring that the right fluids connect safely and productively via the wellbore to the surface and don’t stray along unwanted flowpaths inside or outside the well system.   Operators select through-barrier diagnostics to deliver the crucial information they need to ensure well system integrity throughout the well lifecycle. It is these technology innovations supported by the skills and experience of TGT’s experts and others that are leading the way and reshaping well integrity management as we know it.