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ABSTRACT: It is commonly assumed that the dimensions of an induced microseismic cloud around an Enhanced Geothermal System (EGS) well delineate the “stimulated volume” in which permeability has been increased. This interpretation derives from a self-propping fracture model, wherein shear slip results in some permanent increase of hydraulic aperture. Or, more simply, earthquakes equal permeability. In contrast, here, we interpret microearthquakes (MEQs) directly in terms of the stress and pressure conditions that control earthquake triggering. In many cases, triggering is dominated by fluid pressure changes within a fracture, although increasingly poroelastic and earthquake interaction effects are seen as important.
We present a methodology for inverting spatiotemporal permeability enhancement in a 2D plane around a stimulated well using MEQ data and wellbore records. Our forward model uses a reservoir simulator with an empirically parameterized, time-dependent permeability function at each grid cell. Inversion seeks to quantify, within uncertainty, the parameters of the permeability model. To do this, we use a genetic algorithm that fits the forward model to the wellhead pressure record and the volume density of observed MEQs, using a linear model to convert these to a pressure increase. We apply the inversion to the 2003 Habanero 1 EGS stimulation in South Australia, which injected 20,000 m3 of water into crystalline rock at a depth of 4250 m, inducing approximately 11,000 MEQs. Our findings suggest that robust stimulation (permeability increase by more than an order of magnitude) is limited to a small region around the borehole, about 5% of the volume of the MEQ cloud. This result undermines the traditional view that hydroshearing is an effective mechanism for fracture stimulation and reservoir creation.
Hydraulic stimulation is applied to wells to improve formation permeability. Often, this involves injecting water at high wellhead pressure with the goal of increasing fluid pressure within fractures and promoting their failure (shear and tensile). One way to quantify permeability enhancement is by monitoring for improvements of wellhead injectivity: defined as the ratio of the injection rate to bottomhole pressure. However, when inverting for the distribution of permeability change, wellhead records do not constrain a unique solution. For example, they are unable to distinguish between a modest permeability increase over a large area and a large permeability increase over a small area (Riffault et al., 2018). Ideally, additional data should be used to eliminate non-uniqueness, although regularization (smoothness or Tikhonov) may help.
This paper focuses on compressor systems associated with major production deferments. An advanced machine-learning approach is presented for determining anomalous behavior to predict a potential trip and probable root cause with sufficient warning to allow for intervention. This predictive-maintenance approach has the potential to reduce downtime associated with rotating-equipment failures. The first step in using a machine-learning system is to train the model to identify normal and abnormal operating conditions. The model can then classify real-time data from the equipment and indicate when the equipment's performance strays outside the identified steady state.
In this work we consider the evolution of power spectra of waves during a period of one year. Soukissian and Samalekos (2005) have proposed a segmentation method for significant wave height based on determining periods of stability, increase and decrease using time-series techniques. The second segmentation method is based on the mean value over a moving window, and uses a fixed-width band to determine the change-points in the register. We compare both segmentation methods for several spectral characteristics and give a statistical analysis of duration and intensity of sea states in each case. INTRODUCTION In this work we consider the evolution of power spectra of waves during a period of one year with data from one recording station situated at Waimea Bay, Hawaii. Using the wave-height record we calculate the spectra every 15 minutes in order to capture the short term evolution of some wave characteristics that can be obtained from the spectra. WAFO was used for obtaining the spectra and the spectral characteristics. Soukisissian and Samalekos (2005) have proposed a segmentation method for significant wave height based on determining periods of stability, increase and decrease using time-series techniques. Their method is based on local linear regression and the initial and end points of the intervals are extreme points (local maxima and minima) of the time series. They use a cost function to determine the best configuration of intervals. We apply this method to some spectral characteristics and compare the results obtained with another segmentation method which will be described next. The second segmentation method is based on calculating mean values over moving windows, and using a fixed-width band to determine change points in the wave-height data. Those intervals in which the values remain within a fixed-width interval around the mean are considered to be stationary, those in which the values go above (or below) will be considered increasing (or decreasing).
Korovin, I. S. (Scientific Research Institute of Multiprocessor Computing Systems, SFEDU, RF, Taganrog) | Tkachenko, M. G. (Scientific Research Institute of Multiprocessor Computing Systems, SFEDU, RF, Taganrog) | Khisamutdinov, M. V. (Scientific Research Institute of Multiprocessor Computing Systems, SFEDU, RF, Taganrog) | Kalyaev, A. I. (Scientific Research Institute of Multiprocessor Computing Systems, SFEDU, RF, Taganrog)
Key words: heavy oil, primary cost reduction, data mining, artificial neural networks, genetic algorithms, enhancement of oil recovery, retrospective analysis The paper is dedicated to the possible way of heavy oil primary cost reduction, applying novel enhancement of oil recovery methods. The scheme of the automatic intellectual data handling procedure is considered.
Aud, W.W. (Integrated Petroleum Technologies Inc.) | Poulson, T.D. (Integrated Petroleum Technologies Inc.) | Burns, R.A. (Ocean Energy Inc.) | Rushing, T.R. (Anadarko Petroleum Corp.) | Orr, W.D. (Anadarko Petroleum Corp.)
Summary This paper shows proppant-induced pressure increase (i.e., tip screenout, pack, body pack, etc.) can relate to restricted vertical and lateral proppant distribution in hydraulic fractures. The discussion focuses on interpretation of the character of the pressure response during the proppant stages. Essentially, this pressure response relates directly to the quality of the production response and the level of success. The technology presented has been found to apply to all rock types, frac packs, and low-permeability and water-frac applications. This area of study is based on extensive engineering studies and common sense observation. Prior to publication of this work, this approach fit the reservoir engineering interpretation of the producing character and advanced fracture-treatment-pressure interpretation on a minimum of 1,000 wells. When premature proppant-induced friction occurs in the hydraulically induced fracture, lateral and vertical proppant distribution adjacent to the pay interval can be affected negatively. Restricted proppant distribution results in less effective stimulation because proppant is not distributed well both vertically and laterally adjacent to the pay interval. The fracture stimulation may have been "put away;" but the negative aspects of how the stimulation was designed and implemented may have a significant effect on the resultant production response. To establish the basis for additional thought and investigation, there is discussion about deficiencies in overly simplified pretreatment minifracture-analysis procedures. Many of these analysis methods are not focused on the proppant-induced friction character, and therefore do not optimize proppant distribution. Discussion is provided regarding differences in the proppant-induced friction character of various fracturing fluids which is not an inherent variable typically included in fracture-treatment-design methodology. Introduction The technology presented is derived from a significant volume of work based on an integrated engineering approach to determine the effectiveness of the completion and stimulation method. Over the last 6 years, the technical advancement by Integrated Petroleum Technologies Inc. (IPT) presented in this paper has been extensive in the application of this area of study. The resultant production responses in many areas have been significant, supporting the credibility of the technology presented. During the mid-1990's, downward proppant movement (i.e., clustering, settling, convection) in hydraulic fractures received significant attention in technical papers, forums, meetings, etc. It was depicted as a dominant variable in hydraulic fracturing and, if not addressed, the reason many wells did not produce properly. Proppant was theorized to move to the bottom of the fracture and not be adjacent to the pay interval. An approach for minimizing downward proppant movement was to "tip screenout" or "pack" the fracture. The viewpoint existed for many years that a tip screenout is the ideal response. If conductivity is desired, then build the fracture conductivity by screening out or packing the fracture. This may apply in high-permeability, low-modulus rocks; however, packing the fracture in low- to moderate-permeability rocks has been found to be detrimental to desired results. During the early to mid-1990's, many fractures were packed at various levels of pressure increase to minimize the hypothesized severity of downward proppant movement and achieve a tip screenout. Through detailed reservoir engineering evaluation, these packed fractures were determined to have either short effective fracture lengths or skin damage. Our initial evolution was to reduce the level of proppant-induced pressure increase/pack. Excessive levels of proppant-induced pressure increase were determined to be causing damage as a result of polymer dehydration ("polymer squeeze") in the formation and fracture. With proppant-induced pressure increases of less than 1,000 psi, reservoir engineering analysis continued to show effective fracture lengths shorter than expected. Design criteria evolved to a lower (<500 psi) proppant-induced pressure increase. The effective fracture length from reservoir analysis became longer, but still did not meet fracture model-treatment-design expectations. To improve the predictive capability derived from stimulation designs, customized fracture models were developed that matched the proppant-induced friction character observed for various fluids, formations, fracture geometries, etc. Using these customized models further reduced the level of proppant-induced pressure increase. With the application of these customized models, resultant fracture lengths determined from reservoir analyses became longer and matched fracture lengths predicted in the original fracture-treatment design. When evolving in this direction, it was found that many minifracture techniques and standard industry fracture-model usage were flawed and did not rigorously account for proppant-induced friction effects. Standard minifrac evaluation was designed based on leakoff and fracture geometry assumptions during an era when a tip screenout was the ideal approach. These methods were not tailored toward optimizing proppant distribution because they do not focus on the influence of proppant-induced friction. During this same period, we began studying and observing microseismic and tiltmeter imaging of hydraulically induced fractures. Conclusions from these projects relate primarily to hydraulically induced effects and do not discern proppant distribution in the fracture. However, a consistent observation was that injection of proppant affected the imaged fractures. Changes observed in fracture-growth profiles included reduced lateral-fracture growth and additional fracture-height growth, usually upward. Fracture-imaging observations were coupled with the reservoir engineering and fracture-treatment net-pressure interpretation of many wells. The lateral proppant-distribution hypothesis was the consistent logic path that fit all scenarios. If proppant was entering the fracture and building proppant-induced friction, then how was the proppant efficiently distributing vertically and laterally adjacent to the pay interval? Furthermore, what effect does this frictional back-pressure have on the hydraulic-fracture geometry and injection profile of the slurry? As Baree presented in 1991, increased pressure at the fracture tip will cause fracture-height growth. The propped tip that is screening out could be significantly different than the hydraulic tip of the fracture.