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Filev, Maksim (JSC NK Kondaneft) | Soldatov, Vadim (JSC NK Kondaneft) | Novikov, Igor (GeoSplit LLC) | Xu, Jianhua (GeoSplit LLC) | Ovchinnikov, Kirill (GeoSplit LLC) | Belova, Anna (GeoSplit LLC) | Drobot, Albina (GeoSplit LLC)
Abstract The tracer-based production logging technology can be used to obtain the well production data continuously for several years without the need for risky well interventions and expensive equipment. The paper examines the case of placing polymer-coated tracers dopped proppant in a horizontal well with ten multi-stage frac intervals and using two different tracers dopped proppant codes for two frac ports (the first and the last ones) to identify the performance of the far and near zones of a hydraulic fracture. Upon the completion of the hydraulic fracturing operations, the collected reservoir fluid samples were studied in the laboratory. Chemical tracers contained in the samples were detected by flow cytofluorometry using custom-tailored machine learning-based software. The studies helped identify the productivity of each frac port, calculate the contribution of each port in percentage points, and also evaluate the productivity of the near and far hydraulic fracture zones in the first and the last intervals. The analysis provided data on the exact content of oil and water in the production profile for each frac interval. The results of tracer-based logging in the well in question revealed that the interval productivity is changing in the course of several months of surveillance. The most productive ports and those showing increasing oil flow rate were identified during quantitative analysis. The use of tracer dopped proppant with different codes within one multi-stage frac interval enabled detecting a peak release of chemical tracers from the far fracture zone in the initial periods of well operation followed by a consistent smoothing of the far and near zones’ production profiles. Laboratory analysis of reservoir fluid samples and hydraulic fracturing simulations proved the uniform distribution of proppant across the entire reservoir pay zone and laid the foundation for further research required to better understand the fracture geometry and reduce uncertainties in production optimization operations.
Zhang, Peng (University of Texas at Austin) | Sen, Mrinal K. (University of Texas at Austin) | Sharma, Mukul M. (University of Texas at Austin) | Gabelmann, Jeff (University of Texas at Austin) | Glowka, David (E-Spectrum Technologies Inc.)
Summary A tool concept using downhole electrical measurements for mapping electrically conductive proppant in hydraulic fractures is presented in this paper. The method relies on direct excitation of the casing, which is expected to overcome the severe limitations of induction tools in casedhole wells. An array of insulating gaps is installed and cemented in place as a permanent part of the casing string. The envisioned electrical measurements are performed by imposing a voltage across each insulating gap, one at a time, before and after hydraulic-fracture operations. The voltages across other insulating gaps near the transmitter gap are recorded. The proposed tool's response to the geometry of a single fracture was modeled by solving for the electrical potential with a finite-volume method. Previous simulation results have shown that the electrically conductive proppant alters the path of the electrical current in the formation, and this is recorded as differential signals by the string of insulating gaps surrounding the source gap. The simulated differential signals are highly sensitive to a fracture's location, length, and orientation, and less sensitive to the fracture's aspect ratio. However, to enable the implementation of such a practical system, various aspects of the tool concept must be investigated further through simulations. Following our previous work, this paper focuses on the forward modeling of the tool's response to multiple fractures, which demonstrates the influence of these fractures on the signals, and provides important guidance for inverse modeling. Parametric inversion of fractures from synthetic data, generated by exciting various insulating gaps, is solved with very fast simulated annealing (VFSA). Simulation results show that, when multiple hydraulic fractures are present, the voltages measured at the receiver gaps are determined primarily by the fracture that is in direct contact with the excited section of casing. When two fractures touch the same casing section, they induce voltages very similar to those from a single fracture with the same conductivity and volume. Preliminary inversion results that use synthetic data computed from circular fractures indicate that the proposed VFSA can solve for the multiple fractures’ widths and radii at the same time, without requiring numerous forward simulations. Even with noisy synthetic data, VFSA can make good estimates of the fractures’ parameters. This indicates that the VFSA technique is a proper and robust inversion technique for the measured voltages at various receiver gaps.
Abstract Frac hits or "frac bashing" is a fracture-initiated well-to-well communication event that can create production losses (or gains), and on occasion, mechanical damage when frac energy from a stimulated well extends into the drainage area or directly contacts an adjacent or offset well. Pressure increases have been detected in wells at distances ranging from hundreds to thousands of feet from the stimulated well. While these in-zone frac hit events do not pose an environmental problem if there is no failure of containment, there can be some alteration of the production potential in one or both of the wells involved. Frac hits along the preferential fracture plane were an uncommon but known event when the completion method only involved vertical wells, but the rate of incidence has increased sharply as the preferred completion method has shifted to relatively closely-spaced, multiple fractured horizontal wells (MFHW) in low permeability formations such as the mudstone rocks commonly referred to as shales. Mechanical damage within the well and success of methods of prevention, damage control and remediation will be examined by case histories and published contexts of incidents in several basins, but will not be the main goal of the paper. The primary effort will focus on examining causes of production loss and duration of the loss, including looking at production declines pre-hit and post-hit. Known causes include in-situ stress alteration potential, timing of fracture closure, near-wellbore proppant loss, liquid loading, rock-fluid interactions, sludges and wetting factors. Also considered will be geological effects such as regional fractures and linked natural fracture clusters. A main objective will be to identify pressure transient, chemical analysis or other monitoring techniques to identify location and type of damage. Remedial operations are most effective when the potential cause of production losses can be ranked probabilistically and the depth of the production-reducing event can be estimated as near-field or far-field. Analyzing this data will also assist in defining whether chemical or mechanical treatments such as refracturing or a hybrid treatment system may be the best approach.
Bartko, Kirk (Saudi Aramco) | McClelland, Kenneth (Saudi Aramco) | Sadykov, Almaz (Saudi Aramco) | Baki, Sohrat (Saudi Aramco) | Khalifa, Mohamed (Halliburton) | Zeghouani, Mohamed (Halliburton) | Davis, John (Halliburton)
Abstract In the current energy market, operators of unconventional assets must explore new methods that dramatically reduce the cost of recovery per barrels of oil equivalent (BOE) without adversely affecting production. As such, a number of technologies focusing on expanding completion thresholds and mitigating bypassed reserves have recently come on the market. This paper discusses an engineered approach to utilize one such technology. The approach taken is a holistic petrophysical analysis, coupled with a novel controlled pressure pumping technique (CPP), and deployment of degradable diversion pills within each stage to maximize fracture initiations and stimulated volume. The industry has long assumed that flow-through perforations were a relatively predictable process, given that little or no extrinsic evidence suggested otherwise. Recently, major advances in fiber optic technology, performed during both stimulation and production, have demonstrated that flow is actually not equally distributed. During pumping operations, there can be great temporal variation in casing exit points affecting fluid flow, the addition of diversion creates further complexity to this already dynamic environment. To resolve against variability an integrated approach was required. A progressive completion arrangement aided by petrophysical analysis to define and select perforation cluster locations, a new diagnostic fracture breakdown and propagation process to remedy the chaotic nature of initial flow distribution, and well-defined diversion materials and processes to manage exit point discharge was implemented. Wells in the Jafurah area are typically drilled with approximately 5,000 ft laterals. Over time the challenge of improving cluster efficiency, optimizing cluster spacing, and increasing connected stimulated reservoir volume to enhance long-term well productivity has led to several solutions being introduced, including increasing the number of clusters per stage while consequently increasing the pumping rate and using diversion technology.
Summary Development of hard-to-recover reserves in Russia necessitates the development of new technologies and use of those technologies for efficient production of hydrocarbons. One such technology is multistage fracturing in horizontal wells. Beginning in 2010, such technologies have been widely used in many regions. A liner with swellable or hydraulic packers for separation of intervals and fracture ports opened with balls or actuated with the help of coiled tubing is the simplest and most economically effective method for completion of horizontal sections of boreholes. Well production using multistage fracturing helps maximize initial flow rates and hydrocarbon extraction; however, production declines over time can be significant and, in some cases, it is necessary to perform repeated reservoir stimulation treatments to maintain an economic production level. Refracturing wells with shifting sleeves is complicated because it is necessary to perform selective interval isolation for the target interval treatment. Mechanical isolation involves special tools for well treatment and fracturing, which significantly increases the cost and duration of treatment. Multistage fracturing fluid diversion, with the help of biodegradable diverting agents, is widely used in unconventional reservoirs but has not been used effectively in reservoirs with relatively high permeability. The method discussed in this work is based on injection of a degradable diverting agent, sealing of highly permeable intervals, recovery of permeability of existing fractures, and formation of new hydraulic fractures. This technology does not require any special tools and substantially reduces treatment time. However, such specific technology requires adjustment and calibration to particular formation conditions and completion types. This paper describes the flow diversion multistage refracturing technology tested at Las-Eganskoye field. The technology was tested in formations with relatively high permeability. Results of well treatment and testing allowed for assessing key process procedures and developing measures aimed at adjusting the method to field conditions.
Abstract Fiber-optic measurements are being applied more and more in unconventional reservoirs. Coiled tubing (CT) fiberoptic real-time telemetry can be used to perform distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) providing valuable insight into how fracturing treatments have performed. Changes in vibration during pumping operations can indicate which zones are taking fluid. Fluctuations in observed temperature during pumping can indicate which zone(s) accepted fluid, and warm backs after pumping can determine the qualitative volume of injected fluid that went into each interval. Typically, fiber-optic cables are permanently installed on the outside of casing to monitor the fracturing treatment, other injection operations, and/or production profiles. This methodology presents many risks during installation and well operations, such as pinching, tearing, or perforating the cable or loss of coupling, resulting in poor data resolution. Additionally, once the cable is installed, it is restricted to the specific well or wells installed, hence it cannot be used in other wells or applications as it is a permanent component of the completion. As a result, the technical and commercial value of this technique requires high scrutiny, close supervision, and consideration based on the risk and cost versus value. The case study presented in this paper demonstrates an alternative approach. CT fiber-optic realtime telemetry was used to observe fluid flow along an openhole lateral drilled in an unconventional formation. The study well was produced for a period of time prior to the fracturing operation and the well was then stimulated in a continuous treatment utilizing degradable particulate and fiber material for diversion. Injection tests were performed prior to the fracturing operation allowing the real-time measurements to determine where depleted zones were and what type of rate needed to be pumped for fluid to flow further down the lateral. This allowed for the job to be modified to better target-stimulate the well. Various diversion recipes were pumped both prior to and in between proppant-laden fracturing treatment stages to encourage stimulation along a greater portion of the lateral. CT fiberoptic real-time telemetry was initially deployed to measure the well under static conditions to determine productive zones along the lateral prior to stimulation. It was then used to determine the relative success of each diversion stage during the stimulation treatment. The diagnostics provided by the CT fiber-optic real-time telemetry allowed for a better understanding and optimization of the diversion recipes than other methods. Results presented in this paper show the lessons learned and best practices moving forward for diverting in openhole fracturing treatments. These lessons learned may also be applied to refracturing treatments. Furthermore, CT fiber-optic real-time telemetry can be used in other wells to fine-tune diverter and fracturing fluid recipes.
Abstract In unconventional reservoirs, the well life cycle includes drilling, completion, flowback, and production. The analysis of the fracturing pressure, flowback, and production data provides an early estimate of the stimulated rock volume (SRV) and reservoir flow capacity. In this paper, we present a methodology for using the average treatment pressure and hourly flowback data to characterize reservoir connectivity as an early indicator for long-term productivity. We will also show that performing flow regime analysis during the flowback period provides a greater understanding of the initial fracture conductivity (via bilinear flow) and reservoir connectivity (via linear flow). This early time analysis also sheds light on sweet spots (or geologically favorable areas) and effectiveness of the completion practices for business decisions. In this paper, we have modified the well-known single-phase diffusivity equation to include simultaneous flow of oil, water, and gas in the reservoir. Furthermore, we used fracture treatment pressure, flowback and production data from several Eagle Ford and Bakken wells to demonstrate the value of completion and flowback data and their relation to the long-term performance of wells.
Abstract Multiple fracture placements in single wells have a sixty year history with first applications soon after hydraulic fracturing was patented. Fracturing technology has been applied to offshore deviated wells, sand control wells, tight gas, coal, chalks, shales and conglomerates in turn as "conventional" reservoir limits were reached and each "new unconventional" reservoir was encountered. As fracturing technology was adapted to make an "unconventional" reservoir into a conventional reservoir, the adaptations and evolutions needed became part of the technology tool box waiting for the next challenge. Each innovation improved and stretched the reach of completions and production engineering as new findings were incorporated to monitor, model, optimize and extend the ranges of fracturing use for high and low temperatures, high stress formations and a variety of other challenges. This review looks at the development of multi-fractured wells from its first application in vertical wells where one well could now do the task of three wells, to the first modern application of highly multi-fractured horizontal wells used in chalks, shales and tight oil and gas reservoirs. The technical focus is on the learning procession covering details of casing wear, cyclic pressure application, isolation mechanisms, perforation placement, well spacing and fracture spacing. The technical literature and field learnings have both been searched for applicable information with a surprising variety of engineering application details brought forth that are useful in optimizing a single well or a whole development.
Abstract Chemical water soluble tracers ("WSTs") have been routinely used in hydraulic fracture stimulations in attempts to verify and quantify load recovery from multi-stage stimulations. Load recovery is often interpolated with production data by assuming percent chemical recovered for a given stage directly correlates to that stage's production contribution. This assumption is often verified by a running production logging tools. New solid chemical oil soluble tracers ("OSTs") can now be utilized as a direct indicator of oil flow and production from deep in an individual stages’ fracture. Qualitative analysis gives an early "yes" or "no" to oil flow from each stage, while quantitative analysis may be achieved using relative concentrations of OSTs recovered, and reservoir and flow assumed conditions. OSTs may be used in conjunction with water soluble chemical tracers, or as a stand-alone tracer to determine oil flow from individual stages. The purpose of this paper is to introduce utilizing solid particulate OSTs as a viable methodology to understand individual fracture stage oil contribution in horizontal wells. The results presented in this paper were derived from a three well pilot project performed in the Lower Marmaton formation in Roger Mills County, Oklahoma. An investigation of hydraulic fracture stimulation efficiency was undertaken to determine if individual stimulation stages landed in either 100%, or only a portion of the pay sand, were contributing to the well's oil production. If so, to what extent? The reservoir pay thickness, along with the presence of second sand, influenced wellbore placement in that the drill bit can weave between the sands and the bounding shale layers. Also investigated was the magnitude the stimulation job had on offset producing wells. This was done by collecting and analyzing offset well production for the newly injected WSTs and OSTs. Preliminary results indicate offset communication between certain wells did occur, and the zones experiencing communication appear to have reduced contribution in the subject well's production.
Vassilellis, George D. (Gaffney, Cline and Associates) | Li, Charles (Gaffney, Cline and Associates) | Bust, Vivian K. (Gaffney, Cline and Associates) | Moos, Daniel (Baker Hughes Incorporated.) | Cade, Randal (Baker Hughes Incorporated.)
Abstract The "Shale Engineering" approach and modeling addresses production forecasting in shale and tight formations. This new reservoir simulation methodology relies on modeling the propagation of the stimulated rock volume from the near-well vicinity to deep into the formation. Simulation models are built for individual fracturing stages and validated by matching treatment pressures and rates while conforming to geomechanical and microseismic observations. Stage models are then combined into a larger well model where individual stage contribution and early production performance are matched. This approach was applied on a project that was developed by EQT in an Upper Devonian shale formation in West Virginia. Data available for this project included fit-for-purpose formation evaluation description, production logs and downhole microseismic data with advanced processing and interpretation. The results provided a good match to early well performance, despite the complexity of having to match a combination of shales and partially depleted tight sandstones that had been stimulated by foam fracturing with proppant. This approach can be used not only to predict production, but also as a practical platform for field development design and optimization. Furthermore, the matched results validated the shear stimulation model developed by the authors for this type of application. The approach makes it possible to exploit microseismic observations in a more realistic way in order to describe the stimulated rock volume (SRV), and it explains early-life production logs that indicate uneven fracturing stage contribution. The model also can relate stimulation effectiveness to pre-existing formation rock and fluid properties, and thus can be used as a guide to identify optimal formation targets. The "Shale Engineering" approach hinges on the premise that when unconventional "tight rocks" containing hydrocarbons are modified by hydraulic fracture stimulation, the process converts them into "reservoir rocks". In addition, interpretation of the newly created "artificial reservoirs" is accomplished through multi-displinary expertise that is focused on providing a rate performance and predictive model to aid in reservoir development. Because unconventional resource/reservoir formations are unique and subject to a wide range of conditions, they require a production predictive method more suitable for this task than the commonly used "Type Curves". The advantage of the "Shale Engineering" approach is that it allows validation with parameters that can be available at an early stage of the well life, which in turn are useful to constrain model solutions. It also offers the means to include geomechanics in a practical workflow that allows systematic workflow allows for step-by-step validation of the model. The suggested simulation process uses commerical software and it can be applied to either simple or complex cases.