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Understanding out of zone frac growth can lead to designing stimulation programs that can effectively enhance production from adjacent horizons. The effectiveness of the stimulation program can be assessed by incorporating monitoring programs that include instrumentation to detect seismic events over a broad range of magnitudes from the smallest detectable events with magnitudes below zero (microseismic) to larger events with magnitudes above zero (induced seismic), typically related to larger pre-existing fractures or faults. Stimulating these larger structures could lead to loss of fluid from the reservoir and affect estimates of stimulated volume. In this study, we examine data recorded using a typical downhole microseismic wireline supplemented with a near surface array designed to record induced seismic events. In this study, two horizons were stimulated. The intent of the program was to stimulate both zones by stimulating wells in the lower horizon by increasing pressure rates both early and late into the injection program in the upper horizon. About 4500 microseismic events and 28 induced seismic events were observed. These larger events represent approximately 83% of the total seismic energy released during the stimulation, which, if only using standard recording, would have been misinterpreted as microseismic events and thereby would not have contributed to the overall energy dissipation levels. The larger events were associated with fractures with lengths varying from about 40 m to over 110 m, whereas the microseismic fracture lengths varied from ~5 m up to ~ 35m. The microseismic and induced seismic events could be used to identify growth from the upper to lower horizon at different pressure rates. The occurrences of larger magnitude events appeared to precede pressure increases in the program, suggesting that larger structures were activated as a result of the injection program even before pressures were increased. This observed process sets the foundation to better control stimulation programs.
Hydraulic fracturing in naturally fractured reservoirs is known to generate seismicity due to the interaction of injected fluids with the pre-existing fracture network. Typically, the observed moment magnitudes (Mw) for such operations are small, usually with Mw < 0. To map the seismicity during these injections, geophones (utilizing 15 Hz) are typically deployed in arrays in nearby wells. From such configurations, information on the relative stimulation volumes and overall fracture dimensions can be obtained. However, the ubiquity of these high-frequency instruments has profound implications for the reliability of magnitude estimates for the largest events associated with these treatments. To address this concern, accelerometers and lower-frequency geophones can be installed close to surface to characterize events over a wider magnitude range. Furthermore, these sensors can be combined with the high-frequency downhole geophones to monitor (hybrid sensor network) the full bandwidth of activity that can occur during fracture stimulation programs thereby providing a more complete picture of fracturing for stimulation design purposes.
ABSTRACT: To obtain a full characterization of subsurface stress, both principal stress magnitudes and orientations are necessary. Knowledge of principal stress orientations is particularly important to wellbore stability analysis during drilling of inclined wellbores, hydraulic fracturing operations, and completion design. The assumption of leaving one principal direction vertical while the other two are in the horizontal plane is very often well justified geologically. Under this assumption, by estimating the orientation of maximum horizontal stress, one would characterize the orientation of the other two principal directions as well, hence all three principal directions. Investigation has been performed of well break out, drilling-induced fractures, and natural fractures from image logs in sites of Ordovician and Cambrian aged tight sands in North Africa which have had a complex tectonic history. Separation and collision of Laurasia and Gondwana continents in the Devonian age, followed by the early Cretaceous Austrian deformation and tertiary collision of the Africa/Arabia and Eurasian plates are tectonic events shaping the geology and structure of the area. Drilling-induced fractures and borehole breakout justified by solutions derived from Kirsch's equations around the wellbore are traditionally considered hard data used to estimate the orientation of current day maximum horizontal stress. This work describes the use of natural fracture geometry (dip and dip azimuth) gathered from the same image logs, combined with Mohr Coulomb shear failure (Modes II and III) considerations, to infer local paleo stress orientations and stress regime. The results are further compared to the current day stress orientation inferred from drilling-induced fractures and wellbore breakout. The results exhibit a good match for sites evaluated, indicating that natural fractures under assumption of different modes of failure can be used to infer stress orientation. The claim that natural fractures are created during the whole geologic history of the area and might not be a reflection of current day stresses can be challenged by the fact that the stress states seem to be observed until present day in the sites investigated. Further, by considerations of several modes of natural fractures creation in combination with tectonic local history knowledge, one can infer the geological events which created these fractures aiding reservoir characterization especially in the modeling of a natural fracture network.
To stimulate their oil recovery, oil companies carry out hydraulic fracturing jobs. In this aim the characterization of the fracture, as fluid path, is crucial. It is no longer necessary to prove that the microiseismic monitoring of hydro-fracturing experiments can be used for fracture mapping. Nevertheless, monitoring from treatment well is still a challenge. Using the field experience gained over 20 jobs, we present here a review, as objective as possible, on microseismic monitoring performed during fracturing operations from the injection well (treatment well). Over these last five years, we managed to collect a significant database/catalogue of frac jobs monitoring results, yielding us to keep learning, step by step. Various configurations of the tools in the reservoirs and various probes were experienced. The stimulation jobs were carried out in different types of overburdens, and various behaviours of the formations have been observed. The reservoir behaviour lead to fracture mapping and characterization in successfull cases; however, unconsistent acoustic response was also detected. This is all this feedback we now present here, keeping in mind that these assessments are to be seen just as a starting point within an ongoing learning process.