Imaging of microseismic data is the process by which we use information about the source locations, timing, and mechanisms of the induced seismic events to make inferences about the structure of a petroleum reservoir or the changes that accompany injections into or production from the reservoir. A few key projects were instrumental in the development of downhole microseismic imaging. Most recent microseismic projects involve imaging hydraulic-fracture stimulations, which has grown into a widespread fracture diagnostic technology. This growth in the application of the technology is attributed to the success of imaging the fracture complexity of the Barnett Shale in the Fort Worth basin, Texas, and the commercial value of the information obtained to improvecompletions and ultimately production in the field. The use of commercial imaging in the Barnett is traced back to earlier investigations to prove the technology with the Cotton Valley imaging project and earlier experiments at the M-Site in the Piceance basin, Colorado. Perhaps the earliest example of microseismic imaging using data from downhole recording was a hydraulic fracture monitored in 1974, also in the Piceance basin. However, early work is also documented where investigators focused on identifying microseismic trace characteristics without attempting to locate the microseismic sources. Applications of microseismic reservoir monitoring can be tracked from current steam-injection imaging, deformation associated with reservoir compaction in the Yibal field in Oman and the Ekofisk and Valhall fields in the North Sea, and production-induced activity in Kentucky, U.S.A.
S U M M A R YIn situ stress monitoring of crustal rocks is desirable as it yields insights into earthquake mechanisms, volcanic eruptions and changes in hydrocarbon reservoirs. Shear wave splitting, induced by stress-controlled cracks in the shallow crust, provides a way to infer this stress. Temporal variations in these observations can be difficult to quantify due to scatter in the data and discontinuous observations. Here we present evidence of temporal variations in shear wave splitting from a continuous time-series with a high occurrence of microseismic events recorded in a borehole. We interpret these observations in terms of stress-controlled cracks and are able to infer changes in stress and, via modelling, suggest the cause of the anisotropy. Possible origins of the temporal variation in per cent anisotropy are tidal or oil-field production processes. Our results suggest that shear wave splitting is a viable probe for inferring changes in crustal stress in cracked rock.Observations of crack-induced seismic anisotropy provide insights into crustal stress, and its temporal variation yields insight into changes in that stress (Gupta 1973). However, convincing measurements of temporal variations are difficult to obtain because of scatter in the data and non-continuous recording intervals. Here we present observations of anisotropy inferred from microseismic events at the Valhall oil reservoir (North Sea). The data set provides an ideal opportunity for studying stress changes as we have a continuous 56-day time-series with an average of 15 events per day, recorded on an string of six three-component geophones. The area is prone to large stresses-the seafloor has subsided by more than 4 m since production started and borehole breakout is common in this area. Large variations in shear wave splitting, which is arguably the best indicator of anisotropy, are observed and interpreted in terms of stress modulation of at least one crack set.Shear wave splitting occurs when a shear wave enters an anisotropic medium. The shear wave is split into approximately perpendicular fast and slow components and is akin to optical birefringence. The polarization of the fast direction (φ) is related to the orientation of the anisotropic symmetry axes whereas the lag time * Current address
Summary Flowback data from seven multifractured horizontal tight oil/gas wells in Anadarko Basin show two separate regions during the single-phase water production. Region 1 shows a dropping casing pressure, and Region 2 shows a flattening casing pressure. This paper investigates the flowback behavior of the two regions, and illustrates how flowback data can be interpreted to estimate effective fracture pore volume, and to investigate its relationship to completion-design parameters. We construct diagnostic plots to understand the physics of Regions 1 and 2. Region 1 represents pressure depletion in fractures, and Region 2 represents the hydrocarbon breakthrough into the effective fracture network. The results of our analyses indicate that the duration of Region 1 depends on initial reservoir pressure and hydrocarbon type. We apply a previous flowback model (Abbasi et al. 2012, 2014) on Region 1 to estimate effective fracture pore volume, and also propose a procedure to estimate fracture compressibility by use of diagnostic-fracturing-injection-test (DFIT) data. The results suggest that the estimated effective fracture pore volume is very sensitive to fracture compressibility, and is generally larger than the final load-recovery volume, and less than the total injected-water volume. The results also suggest that most of the effective fractures are unpropped, and host the nonrecovered fracturing water. We investigate the relationship between the estimated effective fracture pore volumes and completion-design parameters, including total injected-water volume, proppant mass, gross perforated interval, and number of clusters, by use of the Pearson correlation-coefficient method. The results show that total injected-water volume, gross perforated interval, and the number of clusters are among the key design parameters for an optimal fracturing treatment. Higher total injected-water volume and closer cluster spacing generally lead to a larger effective fracture pore volume.
Summary The importance of evaluating well productivity after hydraulic fracturing cannot be overemphasized. This has necessitated the improvement in the quality of rate and pressure measurements during flowback of multistage-fractured wells. Similarly, there have been corresponding improvements in the ability of existing transient models to interpret multiphase flowback data. However, the complexity of these models introduces high uncertainty in the estimates of resulting parameters, such as fracture pore volume (PV), half-length, and permeability. This paper proposes a two-phase tank model for reducing parameter uncertainty and estimating fracture PV independent of fracture geometry. This study starts by use of rate-normalized-pressure (RNP) plots to observe changes in fluid-flow mechanisms from multistage-fractured wells. The fracture “pressure-supercharge” observations form the basis for developing the proposed two-phase tank model. This model is a linear relationship between RNP and time, useful for interpreting flowback data in wells that show pseudosteady-state behavior (unit slope on log-log RNP plots). The linear relationship is implemented on a simple Monte Carlo spreadsheet. This is then used to estimate and conduct uncertainty analysis on effective fracture PV by use of probabilistic distributions of average fracture compressibility and gas/water saturations. Also, the proposed model investigates the contributions of various drive mechanisms during flowback (fracture closure, gas expansion, and water depletion) by use of quantitative drive indices similar to those used in conventional reservoir engineering. Application of the proposed tank model to flowback data from 15 shale-gas and tight-oil wells estimates the effective fracture PV and initial average gas saturation in the active fracture network. The results show that fracture-PV estimation is most sensitive to fracture closure compared with gas expansion and water depletion, making fracture closure the primary drive mechanism during early-flowback periods. Also, the initial average gas saturation for all wells is less than 20%. The parameters estimated from the proposed model could be used as input guides for more-complex studies (such as discrete-fracture-network modeling and transient-flowback simulation). This reduces the number of unknown parameters and uncertainty in output results from complex models.
Summary Horizontal wells with hydraulic fractures in tight oil reservoirs show producing-gas/oil-ratio (GOR) behavior that is very different from conventional, higher-permeability reservoirs. This paper explains the reasons for the observed behavior by use of reservoir simulation, with field examples from the STACK and SCOOP plays of the Anadarko Basin in central Oklahoma. A framework for interpreting observed GOR behavior in tight black-oil reservoirs is modeled after the following stages in a well's history. Some stages may not be visible because of the degree of undersaturation, flowing-bottomhole-pressure schedule, finite-conductivity fractures, and duration of the transient-flow period. Stage 1: Early GOR is constant at the initial solution GOR (Rsi) while bottomhole flowing pressure is above the bubblepoint. Stage 2: A rise in GOR as bottomhole flowing pressure declines to less than the bubblepoint. Stage 3: The transient GOR “plateau”, which is characteristic of transient linear flow. Stage 4: A continuous rise in GOR during boundary-dominated flow. Fundamental differences between linear and radial flow, which cause the dependence of GOR on flowing bottomhole pressure, are explained by use of simulation. During transient linear flow, the GOR response to changes in flowing bottomhole pressure is independent of permeability for infinite-conductivity fractures, but not for finite-conductivity fractures. Several practical observations are made. Knowing Rsi and the transient-GOR-plateau level in an area can help one interpret where a well is in its GOR history. Rate-transient-analysis (RTA) diagnostic plots are altered by rising GOR, and sometimes show an early unit slope. During boundary-dominated flow, GOR is more a function of cumulative production than of time; wells with closer fracture spacing have a faster GOR rise with time, but also recover oil more quickly. If compound linear flow develops, GOR can decline late in the well life. The Meramec and Woodford formations in STACK can be history matched without invoking a suppressed bubblepoint caused by pore-proximity effects. The critical gas saturation in the Meramec appears to be in the range of 0–5%. Technical contributions include a framework for interpreting GOR behavior over well life; the effect of changing bottomhole flowing pressure on GOR; the effect of fracture spacing, conductivity, and half-length on GOR; and the effect of GOR on RTA diagnostic plots.
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