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Many production engineers arc beginning to use three-dimensional (3-D) fracture propagation models to design and analyze hydraulic fracture treatments. To use a 3-D model, one must define the layers that comprise the reservoir and develop detailed datasets that accurately describe the layers. The data that are critical for designing and analyzing hydraulic fracture treatments are in-situ stress, formation permeability, formation porosity, reservoir pressure, and Young's modulus. Many times, these parameters can be determined from logs and/or correlated to lithology.
Once the datasets arc obtained, one can use a three-dimensional fracture propagation model to estimate values of created or propped fracture length, width, and height. To understand and improve the fracture design process, the engineer must confirm the estimates of fracture dimensions that are predicted by a fracture propagation model. To verify the model, one must analyze field data to be sure the Field data are consistent with the model results. For example, the net pressure predicted by the 3-D fracture propagation model should closely match the net pressures observed in the field. When net pressure is adequately matched, we usually find that the overall created fracture dimensions predicted by a 3-D fracture propagation model are reasonable. To determine estimates of propped fracture length, one must also analyze post-fracture production and pressure transient data. Because of fracture fluid cleanup problems, we often find that values of propped fracture length generated by analyzing field production data are much shorter than the created fracture length predicted by the fracture propagation model. Detailed engineering studies are often required to reconcile the differences.
To directly measure values of fracture width, one must perform a fracture treatment in openhole, then use a downhole imaging tool to "see" the fracture. Such an approach is not usually practical. In this paper, we will describe a method to qualitatively estimate the propped width profile at the borehole that uses radioactive tracers. Confirming the propped width profile generated by a model with field data can be very beneficial and informative.
We have found that the use of zero wash radioactive tracers can help us learn both (1) where the fracture fluid is going and (2) where the proppant resides in the fracture near the wellbore. Assuming the level of radioactivity is proportional to volume, then the level of radioactivity will also be proportional to the propped fracture width. As such, one can obtain qualitative estimates of propped fracture width at the wellbore using a radioactive tracer where the strength of the radioactive signal is proportional to fracture volume near the wellbore.
The objectives of this paper are to discuss what factors control the fracture width profile and how to obtain data to compute fracture width. We also explain how one can use radioactive tracers to develop data that can be analyzed to determine qualitative estimates of propped fracture width. Finally, we provide several examples to illustrate how one can estimate values of propped fracture width, and how those values can be used to calibrate a 3-Dimensional fracture propagation model.
The information described in this paper can be used by a production engineer to obtain a better understanding of a specific hydraulic fracture treatment.
Arefyev, Sergey (LUKOIL-West Siberia LLC) | Makienko, Vladimir (LUKOIL-West Siberia LLC) | Shestakov, Dmitry (Kogalymneftegaz TME LUKOIL-West Siberia LLC) | Galiev, Marat (Kogalymneftegaz TME LUKOIL-West Siberia LLC) | Ovchinnikov, Kirill (Geosplit LLC) | Malyavko, Evgeny (Geosplit LLC) | Novikov, Igor (Geosplit LLC)
Abstract In recent years, oil and gas producing companies have increasingly migrated towards using tracer-based methods to obtain data on horizontal wells operation. The interest in these technologies is largely due to their ability to obtain data over a long period of time with a radical decrease in the required resources, thereby providing new opportunities for well management and increasing cumulative production. The aim of this article is to compare the results of applying different tracer-based systems in one well. Tracer-based technologies produced by different manufacturers vary in physical principles of operation, as well as in the methods of their injection into the well or reservoir. Tracers designed for long-term work are injected into the reservoir with marked proppant or lowered into the wells in the lower completion cassettes. For the first time, alternative tracer-based systems were applied in one well, ensuring the selectivity of work with oil and water. This allowed us to compare the results and evaluate the technology's advantages and disadvantages. The well was completed by multi-stage hydraulic fracturing with the possibility of subsequent port control using coiled tubing. Each of five well intervals were equipped with two tracer cartridges fixed on an MFrac sleeve on both sides. In addition, proppant with markers was pumped in 3 months. The unique signature of the marker was used for each fracturing stage (5 unique signatures for each of 5 fracturing stages). As a result of this world-first field application of alternative tracer-based systems, valuable analytical material was obtained related to the quantitative analysis of various tracers, the performance of different polymers, and the stability of the tracers’ allocation in the formation fluid. The data obtained confirmed the character of the marked proppant pack washing out with the formation fluid in comparison with the tracer casings attached to MFrac port on both sides. The following results were achieved upon completion: additional tools were obtained for the correlation of data on the tracers amount and concentration, and comparative indicators of different tracer technologies in terms of efficiency and work accuracy were identified. It was also confirmed that the marked proppant is not washed out into the well under these reservoir conditions. The authors of this article were the first to compare the technologies with different approaches to the tracers’ placement in a well within one project. Based on the project results, the obtained data allowed us to answer many pressing questions from oil and gas producing companies related to the comparison of tracer systems.
Warren, Mark N. (ProTechnics Division of Core Laboratories LP) | Dempsey, Christopher J. (ProTechnics Division of Core Laboratories LP) | Woodroof, Robert A. (ProTechnics Division of Core Laboratories LP)
Abstract The lessons learned in the Wolfcamp formation from utilizing completion diagnostics have greatly increased productivity over the years. By employing proppant tracers and subsequent spectral gamma ray logging, along with water-based and oil-based chemical tracers and subsequent produced fluid analysis, trends have been observed, and, where appropriate, changes have been made to the wellbore design, landing interval and subsequent frac design. Throughout the changes, completion diagnostics were utilized and referenced to hydraulic fracturing characteristics, drainage patterns, wellbore spacing, geologic identifiers and overall completion effectiveness, as measured by post-stimulation well performance. This paper reviews many of the insights that have been developed through the use of completion diagnostics in the Wolfcamp formation, as revealed by an extensive database of completed wells. These insights have led to completion optimization, improved well architectures, production enhancements and field-wide cost reductions. The lessons learned should prove useful for both established Wolfcamp operators as well as those new to this play.
From using history matching to recording microseismic; exploration, completion, and production groups in the oil and gas industry don't know exactly where stimulation treatments are placed and how efficient that placement has been. Exploration geologists and geophysicists want to know placement effectiveness to relate current geologic parameters with future potential formations. Completion engineers want to use tubular and downhole hardware systems to be as cost-effective as possible and to minimize total stimulation treatment cost. Production engineers are seeking to maximize production for as long a time frame as possible. Fracturing placement and verification cuts across all segments of an asset.
With recent technology and methodology advancements, the industry can inject particulate oilsoluble tracers (OST) with the proppant and measure those tracers effectively from fracture tip to production tank. While still not accurately describing the exact fracture geometry or parameters such as fracture conductivity (fcd), the industry can now qualitatively measure production from each stage. With each stage uniquely identified by post-fracture production, fracture size and capital expenditure associated with the placement of the fracturing treatment can be optimized.
Broadview Energy recently pumped a fracturing treatment into the 637 m (2089 ft) total vertical depth (TVD) Sparky clastic zone through a 114 mm (4.5") liner string in a horizontal wellbore using mechanically operated sleeves. Broadview Energy sequentially alternated the size of the fracturing treatments along the length of the well between 7.5 t (16, 534 lb) and 5 t (11,023 lb) of 16-30 fracturing sand as the proppant. Alternating the fracture size served to isolate geologic and fluid heterogeneities.
Measuring the OST concentration from each fracture treatment showed results that were not directly proportional with the size of the treatment; namely, a 50% larger stage treatment yielded a 33% improvement in OST return. Using tracer technology to show observable variations of completion methods, Broadview Energy hypothesizes that, with further testing, it would be possible to recognize the threshold in fracture size and prevent diminishing returns in future fracture treatments with similar geologic conditions.
Abstract Microseismic data collected during hydraulic fracturing of shales indicates the position of the fractures created, but not the fractures propped and connected to the well. The goal of this work is to develop a novel tracer-eluting proppant technique that can indicate the extent of propped fractures during hydraulic fracturing. A chemical tracer is encapsulated on proppants with a pH-sensitive polymer coating. These coated proppants can be mixed with regular proppants and placed in fractures during hydraulic fracturing. They would elute tracers during flow back, which can be analyzed to estimate the lateral extent of propped fractures. Laboratory-scale batch tracer release experiments show that the tracer is only released under certain triggering conditions such as increased temperature, salinity or pH. Proof of concept experiment was conducted in a fractured core. The tracer was successfully detected in the flowback fluid and the tracer concentration was accurately estimated by a numerical tracer release model. The location of the tracer eluting proppants can be estimated from the peak tracer time in the flow back water. This proppant-tracer system has the advantages of simple fabrication and good compatibility with a wide range of proppants and tracers. Introduction Production from shales has revolutionized US oil and gas industry in the last decade. Shale reservoirs need to be fractured hydraulically to produce at an economic rate. Long propped fractures that connect to pre-existing natural fractures are needed to maximize productivity for ultra-low permeability shales (Weng et al., 2011). The characterization of the created fracture system is critical for hydraulic fracturing process optimization and technology development. For example, fracture geometry (such as position and length) could significantly affect well productivity and stimulated reservoir volume (Warpinski et al., 2008). Several methods have been tried for characterization of hydraulic fractures. One of the method is microseismic monitoring during hydraulic fracturing (Fisher and Warpinski, 2012; Maxwell et al., 2002). The location of microseismic event can be used as a proxy for slip failure of fractures or faults that usually occurs during creation and propagation of a fracture. This method has a long detection distance and can create a time dependent map of the fracture system (Zoback et al., 2012). However, this method does not indicate if the fractures created remain open (Eisner et al., 2011). Microseismic activity could be affected by the in-situ stress and pore pressure; the fractures created by tensile opening are not detected. Pressure interference can also be used to understand hydraulic fracture geometry by observing the pressure change in a monitor well and a treatment well (Roussel and Agrawal, 2017; Seth et al., 2018). This method is very useful for understanding the communication between wells and stages. However, this method cannot distinguish between propped and unpropped fractures, similar to microseismic method.