Hydraulic Fracture Monitoring Research Articles

Iterative interferometry-based method for picking microseismic events

Continuous microseismic monitoring of hydraulic fracturing is commonly used in many engineering, environmental, mining, and petroleum applications. Microseismic signals recorded at the surface, suffer from excessive noise that complicates first-break picking and subsequent data processing and analysis. This study presents a new first-break picking algorithm that employs concepts from seismic interferometry and time-frequency (TF) analysis. The algorithm first uses a TF plot to manually pick a reference first-break and then iterates the steps of cross-correlation, alignment, and stacking to enhance the signal-to-noise ratio of the relative first breaks. The reference first-break is subsequently used to calculate final first breaks from the relative ones. Testing on synthetic and real data sets at high levels of additive noise shows that the algorithm enhances the first-break picking considerably. Furthermore, results show that only two iterations are needed to converge to the true first breaks. Indeed, iterating more can have detrimental effects on the algorithm due to increasing correlation of random noise.

Robustness of statistical algorithms for location of microseismic sources based on surface array data

Here, we present a statistical simulation study of several array data processing techniques used for the location of sources of elastic waves. The source location problem arises in such engineering applications as radio-communications, acoustics, sonar, meteorology, astrophysics, seismology, etcetera. Recently, this problem has become important for applied geophysics in connection with the modern technology of hydrocarbon production based on the hydraulic fracturing of the surface layers of the Earth’s environment. These techniques are required for the monitoring of hydraulic fracturing through the location of sources of numerous microearthquakes that occur during cracking of crustal rocks. We have established theoretical connections among several location algorithms. In particular, two different theoretical interpretations were proposed for the phase alignment location algorithm, recently proposed for the seismic array data processing. The robustness properties of the phase alignment location algorithm and the adaptive maximum likelihood location algorithm were demonstrated through Monte Carlo simulation in regard to variations of those noise statistical features, which are typical under monitoring of microseismicity at the hydrocarbon production sites. In the framework of the Monte Carlo modeling, we also compared the two mentioned location algorithms with the so-called emission tomography algorithm that is developed for the location of microseismic sources during the monitoring of hydraulic fracturing.

Determination of moment tensor and location of microseismic events under conditions of highly correlated noise based on the maximum likelihood method

ABSTRACTWe examine the problem of localization of a single microseismic event and determination of its seismic moment tensor in the presence of strongly correlated noise. This is a typical problem occurring in monitoring of microseismic events from a daylight surface during producing or surface monitoring of hydraulic fracturing. We propose a solution to this problem based on the method of maximum likelihood. We discuss mathematical aspects of the problem, some features and weak points of the proposed approach, estimate the required computing resources, and present the results of numerical experiments. We show that the proposed approach is much more resistant to correlated noises than diffraction stacking methods and time reverse modeling.

Hydraulic fracture monitoring in hard rock at 410 m depth with an advanced fluid-injection protocol and extensive sensor array

Hydraulic fracture monitoring in hard rock at 410 m depth with an advanced fluid-injection protocol and extensive sensor array

Automated SVD filtering of time-frequency distribution for enhancing the SNR of microseismic/microquake events

Recently, there has been a growing interest in continuous passive recording of passive microseismic experiments during reservoir fluid-injection monitoring, hydraulic-fracture monitoring and fault-movement monitoring, to name a few. The ability to accurately detect and analyze microseismic events generated by these activities is valuable in monitoring them. However, microseismic events usually have very low signal-to-noise ratio (SNR), especially when monitoring sensors (receivers) are located at the surface where coherent and non-coherent noise sources are overwhelming. Therefore, enhancing the SNR of the microseismic event will improve the localization process over the reservoir. In this study, a new method of enhancing the microseismic event is presented which relies on one trace per receiver record unlike other methods. The proposed method relies on a time-frequency representation and noise eliminating process which uses the singular-value decomposition (SVD) technique. Furthermore, the SVD is applied on the matrix representing the time-frequency decomposition of a trace. More importantly, an automated SVD filtering is proposed, so the SVD filtering becomes observation-driven instead of user-defined. Finally, it is shown that the proposed technique gives promising results with very low SNR, making it suitable to locate passive microseismic events even if the sensors are located on the surface.

Localization of microseismic events and determination of source parameters

We examine the problem of localization determining and a microseismic moment tensor of single microseismic event in the presence of strongly correlated noise. This is a typical problem occurring in monitoring of microseismic events from a daylight surface under conditions of a producing field or surface monitoring of hydraulic fracturing. We offer the solution to this problem based on the method of maximum likelihood. The article presents of decision of this problem and the results of numerical experiments. We discuss some features and problems of the proposed approach and estimate the required computing resources. We develop the problem of determination direction of fracture propagation from microseismic event.

Back azimuth constrained double-difference seismic location and tomography for downhole microseismic monitoring

We have developed a new seismic tomography method, back azimuth constrained double-difference (DD) seismic tomography, which is suitable for downhole microseismic monitoring of hydraulic fracturing. The new method simultaneously locates microseismic events and determines three-dimensional (3D) Vp and Vs models for the fracturing zone using differential arrival times from pairs of events and event back azimuths in addition to absolute arrival times. Compared to the existing DD location and tomography method, our method incorporates back azimuth information to better constrain microseismic event locations in the case of poor spatial station coverage such as the linear downhole seismic array generally used for microseismic monitoring. By incorporating the relative arrival time and back azimuth information of events, the extended DD method can provide better relative event locations, and thus can better characterize the fracture distribution. In addition to microseismic locations, seismic velocity anomalies determined around the fracturing zone may also provide valuable information for fracture development. Due to the existence of fractures and fluids, the seismic velocity is expected to be lower in the fractured zone compared to the surrounding regions. Therefore the area of low seismic velocity anomaly may be used as a proxy for the stimulated reservoir volume. We have applied the new method to a downhole microseismic dataset from shale gas hydraulic fracturing. The microseismic events are more accurately relocated than the conventional grid search location method, and they are generally associated with low velocity anomalies.

Passive seismic techniques are developing in many directions

Abstract Yasin C. El-Taha, Petroleum Development Oman, reports on the 6th EAGE Passive Seismic Workshop held on 1-3 February in Muscat with the theme ‘From Data to Decisions’. Attended by approximately 50 participants, the workshop was well received both in discussions during the event and in excellent feedback submitted since. Strongly supported by various operators and service companies, the industry showed renewed commitment to the technology and its development worldwide. After an opening address from keynote speaker Salim Rawahi, geosolutions manager, Petroleum Development Oman (PDO), the workshop continued with a regional focus. From a European perspective, projects were shown with a link to strong drivers or requirements from regula­tory bodies. This situation is currently under heavy scrutiny amongst industry and media alike with high profile projects such as the Groningen gas field. An overview was given of hydraulic fracture monitoring (HFM) in China showcas­ing a rapid rise in uptake of this technology. Monitoring of fracking completions in China has progressed to an advanced stage and is now being regularly used for field development decisions, well placement optimisation and fracking design improvement.

Reservoir characterization using microseismic facies analysis integrated with surface seismic attributes

We have developed the concept of microseismic facies analysis, a method that facilitates partitioning of an unconventional reservoir into distinct facies units on the basis of their microseismic response along with integrated interpretation of microseismic observations with 3D seismic data. It is based upon proposed links between magnitude-frequency distributions and scaling properties of reservoirs, including the effects of mechanical bed thickness and stress heterogeneity. We evaluated the method using data from hydraulic fracture monitoring of a Late Cretaceous tight sand reservoir in central Alberta, in which microseismic facies can be correlated with surface seismic attributes (primarily principal curvature, coherence, and shape index) from a coincident 3D seismic survey. Facies zones are evident on the basis of attribute crossplots, such as maximum moment release rate versus cluster azimuth. The microseismically defined facies correlate well with principal curvature anomalies from 3D seismic data. By combining microseismic facies analysis with regional trends derived from log and core data, we delineate reservoir partitions that appear to reflect structural and depositional trends.

Velocity calibration for microseismic event location using surface data

Because surface-based monitoring of hydraulic fracturing is not restricted by borehole geometry or the difficulties in maintaining subsurface equipment, it is becoming an increasingly common part of microseismic monitoring. The ability to determine an accurate velocity model for the monitored area directly affects the accuracy of microseismic event locations. However, velocity model calibration for location with surface instruments is difficult for several reasons: well log measurements are often inaccurate or incomplete, yielding intractable models; origin times of perforation shots are not always accurate; and the non-uniqueness of velocity models obtained by inversion becomes especially problematic when only perforation shots are used. In this paper, we propose a new approach to overcome these limitations. We establish an initial velocity model from well logging data, and then use the root mean square (RMS) error of double-difference arrival times as a proxy measure for the misfit between the well log velocity model and the true velocity structure of the medium. Double-difference RMS errors are reduced by using a very fast simulated annealing for model perturbance, and a sample set of double-difference RMS errors is then selected to determine an empirical threshold. This threshold value is set near the minimum RMS of the selected samples, and an appropriate number of travel times within the threshold range are chosen. The corresponding velocity models are then used to relocate the perforation-shot. We use the velocity model with the smallest relative location errors as the basis for microseismic location. Numerical analysis with exact input velocity models shows that although large differences exist between the calculated and true velocity models, perforation shots can still be located to their actual positions with the proposed technique; the location inaccuracy of the perforation is <2 m. Further tests on field data demonstrate the validity of this technique.

Distributed Acoustic Sensing for Downhole Production and Injection Profiling

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175211, “Latest Developments Using Fiber-Optic-Based Well Surveillance Such as Distributed Acoustic Sensing for Downhole Production and Injection Profiling,” by Juun van der Horst and Peter in ’t Panhuis, Shell; Nabil Al-Bulushi, Saudi Aramco; Greg Deitrick, Daria Mustafina, Gijs Hemink, Lex Groen, and Hans Potters, Shell; and Rifaat Mjeni, Kamran Awan, Salma Rajhi, and Goos Bakker, Petroleum Development Oman, prepared for the 2015 SPE Kuwait Oil and Gas Show and Conference, Mishref, Kuwait, 11–14 October. The paper has not been peer reviewed. In the past decade, fiber-optic (FO) -based sensing has opened up opportunities for in-well reservoir surveillance in the oil and gas industry. Distributed-temperature sensing (DTS) has been used in applications such as steam-front monitoring in thermal enhanced oil recovery and injection-conformance monitoring in waterflood projects. FO-based pressure gauges are deployed commonly. Significant progress also has been made in maturing other new FO-based surveillance methods such as distributed acoustic sensing (DAS). In this paper, the authors present a recent example of single-phase-flow profiling with DAS. Introduction FO-based surveillance allows for a complete, instantaneous data set from the top to the bottom of the well vs. traditional logging methods that can consume many hours to collect a single trace of a limited interval of the well. A recent development is the use of DAS, which converts a standard fiber deployed over an entire wellbore into a permanent array of microphones. DAS has proved its utility for monitoring of hydraulic-fracturing (HF) operations and for acquisition of vertical-seismic- profile (VSP) surveys and microseismic. A third promising application under development is that of measuring downhole production or injection-flow performance, where DAS can replace the conventional production-logging-tool (PLT) survey for a number of flow regimes and well types. Because the same FO cable can be used for different measurements by connecting the appropriate interrogation unit to the cable, it is, for instance, possible to use DAS for first monitoring the HF treatment during the initial well completion, followed by time-lapse production profiling surveys to assess the (change in) flow behavior for optimizing well inflow/outflow performance or improving the completion design of future producers.

Real-time event location using model-based estimation of arrival times and back azimuths of seismic phases

I have devised a real-time procedure for locating events using an estimation method that analyzes arrival times and back azimuths of phases. The new procedure is applicable to data acquired by local array receivers, such as those used in single-well monitoring as well as by dense receiver networks, and also to noisy waveforms, such as those observed in hydraulic fracturing monitoring if the signal-to-noise ratio is greater than approximately 6 dB. The new procedure uses coalescence microseismic mapping to obtain predictions of arrival times. Based on these predictions, arrival times were estimated by picking the maximum of the ratio of the short-term average to the long-term average of a characteristic function computed for waveforms in an appropriate time window. The estimated arrival times were used in a probabilistic location method, and the probability density function (PDF) of the event location was generated. To locate events for a local array of receivers, the PDFs of event back azimuths obtained using polarizations were combined with the traveltime data to remove directional ambiguities. I have developed this method to generate the PDF of event back azimuths using the average of polarization misfits, which are the differences of the measured and computed polarizations for trial event locations, weighted by the signal-to-noise ratio. Synthetic and field data examples of single-well monitoring of hydraulic fracturing, which required the estimation of event back azimuths in addition to arrival times, were evaluated to determine the effectiveness of the new procedure.

Field trial of seismic recording using distributed acoustic sensing with broadside sensitive fibre‐optic cables

ABSTRACTDistributed acoustic sensing is an emerging technology using fibre‐optic cables to detect acoustic disturbances such as flow noise and seismic signals. The technology has been applied successfully in hydraulic fracture monitoring and vertical seismic profiling. One of the limitations of distributed acoustic sensing for seismic recording is that the conventional straight fibres do not have broadside sensitivity and therefore cannot be used in configurations where the raypaths are essentially orthogonal to the fibre‐optic cable, such as seismic reflection methods from the surface. The helically wound cable was designed to have broadside sensitivity. In this paper, a field trial is described to validate in a qualitative sense the theoretically predicted angle‐dependent response of a helically wound cable. P‐waves were measured with a helically wound cable as a function of the angle of incidence in a shallow horizontal borehole and compared with measurements with a co‐located streamer. The results show a similar behaviour as a function of the angle of incidence as the theory. This demonstrates the possibility of using distributed acoustic sensing with a helically wound cable as a seismic detection system with a horizontal cable near the surface. The helically wound cable does not have any active parts and can be made as a slim cable with a diameter of a few centimetres. For that reason, distributed acoustic sensing with a helically wound cable is a potential low‐cost option for permanent seismic monitoring on land.

Back‐projection stacking of P‐ and S‐waves to determine location and focal mechanism of microseismic events recorded by a surface array

ABSTRACTWe present an automatic method of processing microseismic data acquired at the surface by a star‐like array. The back‐projection approach allows successive determination of the hypocenter position of each event and of its focal mechanisms. One‐component vertical geophone groups and three‐component accelerometers are employed to monitor both P‐ and S‐waves. Hypocenter coordinates are determined in a grid by back‐projection stacking of the short‐time‐average‐to‐long‐time‐average ratio of absolute amplitudes at vertical components and polarization norm derived from horizontal components of the P‐ and S‐waves, respectively. To make the location process more efficient, calculation is started with a coarse grid and zoomed to the optimum hypocenter using an oct‐tree algorithm. The focal mechanism is then determined by stacking the vertical component seismograms corrected for the theoretical P‐wave polarity of the focal mechanism. The mechanism is resolved in the coordinate space of strike, dip, and rake angles. The method is tested on 34 selected events of a dataset of hydraulic fracture monitoring of a shale gas play in North America. It was found that, by including S‐waves, the vertical accuracy of locations improved by a factor of two and is equal to approximately the horizontal location error. A twofold enhancement of horizontal location accuracy is achieved if a denser array of geophone groups is used instead of the sparse array of three‐component seismometers. The determined focal mechanisms are similar to those obtained by other methods applied to the same dataset.

Interferometric assessment of clamping quality of borehole geophones

Borehole arrays are often preferred over surface installations for hydraulic-fracture monitoring of deep experiments due to their proximity to the treatment zone. Borehole geophone strings are typically clamped to the observation wellbore wall using electromechanical or magnetic devices in order for them to be in close contact with the surrounding formations and record the background noise and propagating wavefields related to the microseismic experiments. This contact needs to be maintained throughout the recording time. We have used seismic interferometry to assess the clamping quality of borehole geophone arrays. We determined that the characteristics of the retrieved crosscorrelation functions between a reference receiver and other receivers in an array are indicative of the clamping quality of the former geophone to the borehole wall. We have also defined the concept of separation frequency or emergence frequency as the frequency below which direct body waves propagating along the receiver line are clearly observed on the crosscorrelation gathers. The crosscorrelation gathers associated with poorly clamped geophones show predominantly tube waves or incoherent waveforms. Body waves only emerge below very low separation frequencies. The crosscorrelation gathers of relatively better coupled geophones, on the other hand, have higher separation frequencies. We have applied this method to four different borehole microseismic data sets, labeled here as A, B, C, and D, of which data set D was previously known to suffer from some clamping issues. Data sets B and C with inferred better coupling had separation frequencies of approximately 60 Hz, whereas the other two data sets are characterized by lower separation frequencies, 15 Hz for data set A and 20 Hz for data set D, suggesting relatively poorer coupling.

Neuro-evolutionary event detection technique for downhole microseismic surveys

Recent years have seen a significant increase in borehole microseismic data acquisition programs associated with unconventional reservoir developments such as hydraulic fracturing programs for shale oil and gas. The data so acquired is used for hydraulic fracture monitoring and diagnostics and therefore, the quality of the data in terms of resolution and accuracy has a significant impact on its value to the industry. Borehole microseismic data acquired in such environments typically suffer from propagation effects due to the presence of thin interbedded shale layers as well as noise and interference effects. Moreover, acquisition geometry has significant impact on detectability across portions of the sensor array. Our work focuses on developing robust first arrival detection and pick selection workflow for both P and S waves specifically designed for such environments. We introduce a novel workflow for refinement of picks with immunity towards significant noise artifacts and applicability over data with very low signal-to-noise ratio provided some accurate picks have already been made. This workflow utilizes multi-step hybrid detection and classification routine which makes use of a neural network based autopicker for initial picking and an evolutionary algorithm for pick refinement. We highlight the results from an actual field case study including multiple examples demonstrating immunity towards noise and compare the effectiveness of the workflow with two contemporary autopicking routines without the application of the shared detection/refinement procedure. Finally, we use a windowed waveform cross-correlation based uncertainty estimation method for potential quality control purposes. While the workflow was developed to work with the neural network based autopicker, it can be used with any other traditional autopicker and provides significant improvements in pick detection across seismic gathers.

Hydro‐frac monitoring using ground time‐domain electromagnetics

ABSTRACTAs motivation for considering new electromagnetic techniques for hydraulic fracture monitoring, we develop a simple financial model for the net present value offered by geophysical characterization to reduce the error in stimulated reservoir volume calculations. This model shows that even a 5% improvement in stimulated reservoir volume for a 1 billion barrel (bbl.) field results in over 1 billion U.S. dollars (US$) in net present value over 24 years for US$100/bbl. oil and US$0.5 billion for US$50/bbl. oil. The application of conductivity upscaling, often used in electromagnetic modeling to reduce mesh size and thus simulation runtimes, is shown to be inaccurate for the high electrical contrasts needed to represent steel‐cased wells in the earth. Fine‐scale finite‐difference modeling with 12.22‐mm cells to capture the steel casing and fractures shows that the steel casing provides a direct current pathway to a created fracture that significantly enhances the response compared with neglecting the steel casing. We consider conductively enhanced proppant, such as coke‐breeze‐coated sand, and a highly saline brine solution to produce electrically conductive fractures. For a relatively small frac job at a depth of 3 km, involving 5,000 bbl. of slurry and a source midpoint to receiver separation of 50 m, the models show that the conductively enhanced proppant produces a 15% increase in the electric field strength (in‐line with the transmitter) in a 10‐Ωm background. In a 100‐Ωm background, the response due to the proppant increases to 213%. Replacing the conductive proppant by brine with a concentration of 100,000‐ppm NaCl, the field strength is increased by 23% in the 100‐Ωm background and by 2.3% in the 10‐Ωm background. All but the 100,000‐ppm NaCl brine in a 10‐Ωm background produce calculated fracture‐induced electric field increases that are significantly above 2%, a value that has been demonstrated to be observable in field measurements.

Investigation of Hydraulic Fracture Networks in Shale Gas Reservoirs with Random Fractures

As shown in hydraulic fracture monitoring, the hydraulic fracture path in naturally fractured shale reservoirs is complex, and the method for describing the propagation of fractures in homogeneous sandstone cannot achieve sufficient accuracy when used in shale reservoirs. In this study, a discrete fracture network model is proposed by performing a Monte Carlo simulation on the fracture characteristics of downhole shale cores and shale outcrops in the Longmaxi formation in the Sichuan basin of China. Given the fracture fluid pressure drop and intersections between hydraulic and natural fractures, a 2D numerical model is developed to examine the hydraulic fracture propagation in a randomly fractured shale reservoir using the displacement discontinuity method. Numerical simulations show that (1) the density and length of natural fractures are positively correlated with the complexity of natural fractures when the orientation of such fractures is similarly distributed, (2) the influence of small natural fractures on a hydraulic fracture is localized and cannot change the overall direction of the hydraulic fracture, and (3) hydraulic fractures can cross the natural fracture when the intersection angle and minimum horizontal stress are small enough. The rationality of the numerical model results is supported by the hydraulic fracturing tests on fractured shale outcrops with a true triaxial fracturing system and microseismic monitoring from a hydraulic fracture test well in the Longmaxi shale formation.

C13 and Thomsen anisotropic parameter distributions for hydraulic fracture monitoring

Most shale reservoirs are described assuming transverse isotropy. A full characterization of such reservoirs requires the knowledge of six elastic parameters comprising, for instance, the density; P- and S-wave vertical velocities; and the three anisotropic Thomsen parameters [Formula: see text], [Formula: see text], and [Formula: see text]. For hydraulic fracturing monitoring purposes, the parameters [Formula: see text] and [Formula: see text] are typically estimated from perforation microseismic data by analyzing the variation with phase angles of the traveltimes of direct P-waves and direct SH-waves. The estimation of the Thomsen parameter [Formula: see text] is more challenging because most perforation microseismic data do not exhibit direct SV-waves to which the parameter [Formula: see text] is the most sensitive. A Bayesian inference method is proposed to estimate [Formula: see text] from traveltimes of secondary SV-waves observed on microseismic data. Because the interpretation of the physics underlying the observation of these secondary SV-waves is often not readily available for wellsite operations, a marginalization scheme is used to account for uncertainties associated with not knowing, or only partially knowing, the locations where they originated from. I determined the benefits of the proposed method by applying it to data sets collected in the Jonah field using a single monitoring well. The results revealed a significant variance reduction of more than 15-fold on the posterior probability distribution associated with [Formula: see text] when using the secondary-source SV-waves. Moreover, a more accurate estimate of the microseismically derived fractured volume is achieved with variance reduced by more than a factor of 75.

An efficient GPU implementation for locating micro-seismic sources using 3D elastic wave time-reversal imaging

Locating micro-seismic events is of utmost importance in seismic exploration, especially when searching for unconventional oil and gas resources. The arrival-time-difference approach is the dominant source location method currently used in the field of micro-seismic source location. However, micro-seismic events can be generated by any arbitrary rock movement and are often accompanied by interference noise. Recordings show characteristics of complicated wavelets and low signal-to-noise ratios. Under such conditions, conventional triangulation methods may have difficulty producing reliable locations; time-reversal imaging micro-seismic event location techniques are more promising. Locating micro-seismic events must be performed on-site for real-time monitoring of hydraulic fracturing. Introducing wave equation imaging techniques when locating micro-seismic events will increase the computation time, thus complicating real-time site monitoring. Therefore, the use of graphics processing unit (GPU) devices to accelerate time-reversal imaging micro-seismic event location technology becomes imperative. Three-dimensional synthetic data examples have demonstrated that the GPU-based time-reversal imaging micro-seismic event location method is typically 18 times faster than the central processing unit (CPU)-based implementation. The performance boost afforded by the GPU architecture allows us to locate micro-seismic events in 3D at a lower hardware cost and in less time than has been previously possible.