Understanding Production Logging, Tracers, Microseismic

Production Logging

The horizontal production logging service provides highly accurate measurements of multiphase flow and individual fluids—including oil, gas, and water. Production logging service integrates micro-spinners to measure flow, optical sensors to identify gas and liquid, and resistance spinners to distinguish between hydrocarbons and water. This sensor array is placed around the circumference of the wellbore to measure production fluids and their corresponding flow rates to deliver a complete picture of the well’s production. Well flowing conditions are different for horizontal and vertical wells, which require modifications to the tools and interpretations techniques. Phase segregation and fluid stratification are observed in horizontal wells. These phenomena lead to multiphase flow thus making the responses of production tools unpredictable. The main challenge facing production logging in horizontal wells is that trapped fluids can directly affect production and influence the data from a production log, especially for sensors such as spinners and capacitance tools. Because horizontal wells have dog-legs and undulations, stagnant water may lie either inside or outside the casing in low areas at the bottom of the well, and stagnant gas may accumulate on the high side of hole undulations. However, applications of modern production-logging methods have helped to make significant production gains. Conventional production logging could not evaluate the individual interval contributions or identify the sources of water production. This led to development of new technology tools with a range of small sensors that covered the full width of the wellbore and could be placed close together to improve depth resolution. To avoid the traditional production logging challenges, the tool-string length can be reduced by as much as half, preventing damage to logging tools and minimizing the challenges of compromised data quality. The latest techniques provide real-time holdup and velocity profiles along a vertical axis of the borehole cross-section. The sensors distinguish between gas and liquid using optical refractive index measurements. Thus, it gives a better understanding of production regimes and defining accurate flow profiles, which consequently help in planning more efficient workover or production strategies and improve ultimate hydrocarbon recovery. With the in-depth understanding of oil-gas-water ratios and flow rates, you get the data you need to efficiently manage the production from any of your wells.

Proppant Image Logs

Proppant log provides qualitative as well as quantitative insights into spatial distribution of proppant sand particles from prior stimulation of parent wells. As a child well is being drilled, periodic mud return samples are collected at the rig site and preserved for analysis. The workflow involves systematic cleaning of the samples including various steps such as washing, drying, and segregation of samples into relevant size fractions of interest (< Mesh 20) based on specifications of pumped sand during stimulation of the parent well. Clean samples are imaged using high resolution transparency scanning. Scan images are then systematically analyzed for particles of interest using computer vision techniques. Sample counts are further validated using elemental analysis of smaller sub-samples at various depths of interest. This step is necessary to isolate proppant versus other naturally occurring minerals such as sulphates and carbonates which show similar optical properties. Successfully correlations of proppant distribution against the existing parent well can be made to validate propped versus relatively un-propped zones for a child well at the test site. The additional diagnostic data that is available to validate the primary observations can be utilized. One can correlate spatial proppant distribution against variability in stimulation response based on independent observations such as image logs, microseismic attributes as well as distributed acoustic sensing (from Fiber Optics) response, all of which tend to corroborate one another. This provides unique opportunities to better understand the current state of the reservoir being targeted including zones which are likely more drained relative to others and how the planned completion of the child well can be improved. Finally, this log can be useful is validating optimal well spacing in relatively new fields under development.

Microseismic

Microseismic monitoring refers to a seismic technique that uses fracturing or water-injection-induced microseismic phenomena similar to natural earthquakes but with low intensities during reservoir fracturing or water injection operations to monitor fracture activities and flow mobilities in oil-producing or gas-producing pays to inform decisions regarding reservoir management optimization and the exploration and development of tight reservoirs. Microseismic monitoring provides the real-time heights, lengths, orientations, geometries, and spatial arrangements of fissures produced during construction so that they can be used to optimize the fracturing design, the well pattern, or other development measures and to improve the recovery ratio. Whether the production of unconventional petroleum can be increased, whether its recovery ratio can be improved, and whether its reserves can be effectively produced are all highly dependent on the performance of the fracturing operation. Microseismic monitoring is an effective means of monitoring the fracturing performance in real time. Microseisms, small earthquakes, are induced by the hydraulic fracturing fluid pressurizing the rock. A set of geophones is run in an offset monitoring well some distance away from the injection well to listen for microseisms. The harder and more uniform the rock, the farther sound travels and the more microseisms can be picked up with downhole telemetry. Real-time data are plotted to determine height growth, length of the events from the wellbore, and the field width of the events. On-the-fly changes to the fracturing schedule may then become apparent to influence fracture growth. Final analysis after treatment provides a fracture map showing the length, width, and height growth of the fracture. This aids the design engineer in sizing fracture designs for future treatments. It also allows the reservoir engineer to optimize placement of wells to effectively drain production. In the case of low permeability coals, it can be used to validate a complex fracture network development that would enhance permeability and increase gas production.

Chemical Proppant Tracers

Chemical tracers are used during multi-stage hydraulic fracturing treatments to tag individual fracture stages with a unique chemical tracer. A tracer is simply a chemical compound that is designed to faithfully follow the flow path of its carrier fluid while travelling through the reservoir. Water tracers are used to tag the fracture fluid injected during the treatment, while hydrocarbon tracers are used to tag the oil or gas in place in the reservoir. The tracers are HSE-friendly, non-toxic, and are easy to inject during the fracture treatment without any negative impact on completion. To obtain quantitative data regarding the fracture diagnostics, tracers are injected at a constant concentration (ppm or gpt) during the entire fracture treatment. Since each fracture stage is traced at the same concentration and dilution is assumed as the only mechanism influencing tracer concentration, the flow back concentration of each individual tracer is directly proportional to the flow rate of fracture stages tagged by the tracer. This data can be used to benchmark completion designs and to better understand the geological “sweet spots” within a typical shale formation by looking at stage tracer recoveries. The application of the tracers throughout each wellbore can be designed to mitigate or counterbalance variables out of the controllable completion engineering parameters such as heterogeneity along the wellbores, existing reservoir depletion, well hydraulically driven interactions (frac hits) as well as to minimize any unloading and production biases. The typical actionable datasets gathered via this tracer evaluation include:

• Stage load recovery & cleanup efficiency

• Formation water identification

• Hydrocarbon production allocated by stage

• Heel-to-toe production ratio

All chemical tracers used for fracture analysis undergo through rigorous laboratory and field screening. Selected tracers should behave as expected and guarantee reliable and repeatable analysis. Chemical purity, thermal stability, and tracer partitioning are just a few examples of screening criteria, which determines the field viability of a tracer compound. The sampling of produced fluids during flowback and production is one of the most important components during a tracer test but is often the most overlooked. In order to obtain accurate sample data, samples should be taken frequently and on a pre-determined schedule based on the well’s production rate. Samples should never be caught from a flowback tank containing produced fluids originating from multiple wellheads. It is best to sample from a test separator containing a moving stream of fluids from only one individual wellhead. If a test separator is not available, a commingled wellhead sample can be caught and separated in the lab. For mass balance to be accurate (tracer in vs. tracer out), the flowback and production data for the individual well should be accurately recorded as well. Water and oil (or gas) samples are collected during the flow back period and sent to the lab for analysis. Concentration for all tracers in the samples will be measured and recorded. Fracture analysis is carried out using tracer flowback data. This analysis is primarily based on mass balance. Integrating tracer concentration with water and oil production rates yields the total mass of tracer recovered from each stage. The ratio of recovered tracer mass to the total injected tracer mass reveals the stage load fluid cleanup efficiency and oil tracer recovery. Comparing the concentration of each tracer yields the stage inflow contribution of frac fluid and hydrocarbon production. Such information can further yield the heel to toe ratio.

Engineered Nano-Tracers

The company QuantumPro, Inc. offers tracer portfolio with more than 100 uniquely tagged proprietary particles developed from cost-effective and environmentally friendly materials. During the pre-commercialization testing protocol, each smart tracer is evaluated for specific characteristics, including high thermal (up to 2,000 °F) and pressure stability, settling time, particle size distribution (PSD), and elemental composition, as well as reservoir static and dynamic adsorption. The next phase involves aligning and refining each smart tracer with the pre-planned multi-stage fracture stimulation design, pumping schedule and the estimated completion flow profile. This step validates performance under real-world subsurface conditions, including recovery efficiency under minimum and maximum flow velocities at the stage level .As demonstrated in a number of unconventional wells, the ultra high resolution nanoparticle tracer portfolio consistently quantifies the flow behavior of individual stages, while narrowing the wide economic chasm that previously made stage-level flow mapping inaccessible to mainstream shale wells. The non-intrusive nanoparticle based tracers are proven to deliver accurate and near-real-time detection beyond the capabilities of conventional chemical tracers and DNA sequencing technologies. The non-radioactive intelligent tracers were formulated for subatomic detection accuracy, enabling exceptional surface recovery rates, which are proportionate to the hydrocarbon production. Based on differentiating diagnostic field data, the technology exhibits a high level of precision in mapping field wide inter-well communications, or infill frac-hits. When coupled with subatomic measurements, the tracers provide accurate and robust detection capabilities. Moreover, laboratory analyses incorporating big-data analytics, advanced 3D reservoir flow visualization and nanoparticle detection capabilities provide accurate, calibrated and cost-effective completion diagnostics results.

A single tracer formulation is equally compatible with both oil and water. Consequently, only one tracer type is required for each stage, effectively cutting the cost in half, compared to conventional chemical tracers. Unlike their liquid counterparts, once the smart tracers are deployed, they tend to stay in the proppant pack, rather than quickly dissolve within the fracture network, thus extending the recovery time considerably and enabling continuous measurement and monitoring of the production profile for up to seven months after deployment. Furthermore, the particles are incapable of penetrating into the small fissures that open up during the hydraulic fracturing process, mitigating the false positive frac-hit signals that are all-too-common with chemical tracers, and avoiding unnecessary and costly reactive measures. The smart tracers are easily deployed with a precise automated dosage system during the stage pumping process and require no additional surface equipment or downhole modifications to the completion. The samples are collected directly at the wellhead, enabling detection of the best possible signal, as the tracers come out from the well.

Fiber Optics

Premium fiber optic-enabled distributed temperature surveys (DTS) and distributed acoustic sensing (DAS) both deliver a high degree of detection accuracy during fracturing operations and can increase overall well costs up to $1 million/well, depending on well size and complexity. DTS and DAS systems, which must be installed prior to completion, necessitate extensive well stimulation and completion modifications with pre-defined fiber positioning and phasing behind the casing. Many times, this requires oriented perforations with a very narrow margin for error accompanied by pumping changes, all of which come at costs beyond the risk-return profiles of most shale operators. Additionally, the fibers detect inter-well communication during the fracturing process at each stage but are less proficient at mapping inter-well communication during production, due to sensing requirements for acoustic and temperature changes. The high cost associated with DAS and DTS systems, in conjunction with the significant risk of fiber damage or total signal loss during contemporary plug and perf operations, greatly reduces the repeated deployment of this technology for many operators.

Carbo Ceramics - https://www.carboceramics.com

QuantumPro, Inc. - https://www.carboceramics.com

Renegade Wireline Services (RWLS, LLC) - https://renegadewls.com

Resmetrucs - https://resmetrics.com

SPE Paper No. SPE-204169-MS

https://jpt.spe.org/twa/production-logging-identifying-and-remedying-poor-well-performance