The deeply buried reservoirs of Wenchang Formation in the Lufeng Depression, Pearl River Mouth Basin, display strong heterogeneity, and the major controls for the development of high-quality reservoirs remain unclear. To address these issues, we conducted a series of experiment analyses, including petrographic microscope, scanning electron microscopy, and X-ray diffraction, and analyzed the impacts of sedimentation and diagenesis on the quality of deeply buried reservoirs. The results demonstrate that the sandbodies of subaqueous distributary channel and mouth bar deposited in lowstand systems tract (LST) and highstand systems tract (HST), as compared to the beach-bar and subaqueous fan sandstones deposited in transgressive systems tract (TST), have coarser grain size, higher quartz content, and lower muddy matrix content, which induced stronger anti-compaction capability, higher preservation of intergranular pore spaces, and thus better reservoir qualities. The reservoir types developed in subaqueous distributary channel and mouth bar are mainly types I, II, and III with medium-low porosity and low-ultra low permeability, while beach-bar and subaqueous fan mainly developed type III reservoir with low-porosity and ultra-low permeability. The reservoirs developed in E2w of the study area have undergone strong compaction, intense dissolution, but weak cementation. The subaqueous distributary channel and mouth bar reservoirs in LST are adjacent to Ew4 source rock in spatial distribution, resulting in strong organic acid dissolution, and developed numerous dissolved pores. The charging of hydrocarbons before deep burial further inhibited the later compaction and cementation and protects the preservation of residual primary intergranular pores and secondary dissolved pores. The combination of these factors leads to the development of the abnormally high porosity and high-quality reservoirs in LST. The results of this study reveal the genetic mechanism of deep, high-quality reservoirs in the rift basin and guide the selection of high-quality reservoirs in the later stage.
Manual seismic horizon picking is the least efficient interpretation technique in terms of time and effort. The loop-tie is a key “element” and the most time-consuming task in manual horizon picking, which ensures the accuracy of horizon picking. Autopicking techniques have been used since the early 1980s. However, there are few studies simulating the procedure of manual seismic horizon picking and quantitatively evaluating the autopicked horizons. In our proposed method, we perform autopicking on inline and crossline seismic vertical slices independently, similar to the manual horizon picking procedure. We then evaluate the picked horizons using a loop-tie step similar to the loop-tie checking in manual horizon picking. To simulate the loop-tie step in manual picking, we define two dip attributes for each time sample of seismic traces, which are the “left” and “right” reflector dips. We only preserve the portions of the tracked horizons that meet the defined loop-tie checking. Next, we merge the tracked horizons centered at the seeded seismic traces. The two-way traveltime of the merged horizons functions as a “hard” control for the final step of autopicking. Finally, we use the seismic dip attribute to track the horizons over the seismic survey under the hard controls. The real data demonstrate that our algorithm can extract accurate horizons near discontinuities such as faults and unconformities.
Today's 3-D seismic surveys usually contain hundreds of inline and crossline vertical seismic slices. Seismic interpreters usually need to spend weeks or even months for manually picking horizons on vertical seismic slices. Researchers have developed algorithms to accelerate horizon picking and most algorithms employ the seismic reflector's dip as the input. However, the computed seismic reflector's dip is usually inaccurate near and across the discontinuities in the seismic images. Note that the time samples which belong to the same horizon should have approximate similar seismic instantaneous phase values. We propose to automatically track the seismic horizon simultaneously considering the seismic reflector's dip and instantaneous phase attributes. Our algorithm aims to achieve three objectives: 1) minimizing the difference between the dip computed using tracked horizon and seismic dip attribute, 2) minimizing the difference among instantaneous phase value of the time samples on the tracked horizon, and 3) the tracked horizon exactly passes through user-defined control points (seeds). A constrained conjugate least-square algorithm is employed to solve our optimization problem. The applications show that the tracked horizon which only uses dip attribute would "jump" from one seismic event to another seismic event near the unconformity zone. However, the horizon tracked using the proposed method strictly follows the same seismic event over the whole seismic survey.
Stratigraphic correlation of well logs is based on interactive interpreter-based pattern recognition. A skilled interpreter identifies similar patterns (such as upward fining and coarsening) in user-defined well sections and links them using either a conscious or subconscious stratigraphic model. This manual stratigraphic correlation of numerous wells in mature fields can be time-consuming and error-prone. To expedite the process of stratigraphic correlation, we have performed semiautomatic stratigraphic correlation of wireline logs from multiple wells using improved dynamic time warping (IDTW). IDTW uses semblance, which compares the shape of the well logs, to replace the Euclidean distance in pairwise error computation. The resulting error matrix is compatible with the lateral nonstationary variation of well logs in the same formation. The workflow begins with interpreting stratigraphic well tops on user-defined well sections that is similar to the current process of stratigraphy analysis. The interpreted wells are then treated as reference wells to aid in interpreting well tops for other wells. Necessary manual interventions are incorporated during the semiautomatic stratigraphic correlation process. We applied our method to two experimental fields: a sand-rich reservoir and a mud-rich reservoir. The applications illustrate that our method performs well in aggradational strata and successfully predicts discontinuities with manual interventions.
Time-depth relationships (TDRs) can connect seismic and wireline logs, both essential characterization data of reservoirs. The seismic well tie is always a complex work on account of the complicated reservoir structures. Since seismic and logging data are responses of reservoir architectures, the seismic well tie can be efficiently improved constrained by the reservoir architectures. This study adopts a clastic reservoir as the study area. Three architecture modes (i.e., normal cycle mode, inverse-normal cycle mode, and homogeneous-normal cycle mode) are summarized based on combinations of architecture elements. For the generation of the synthetic seismograms, optimized wavelets (i.e., wavelet A, wavelet B, and wavelet C) are suitable for the wells belonging to normal cycle mode, inverse-normal cycle mode, and homogeneous-normal cycle mode, respectively. Precise TDRs are established by matching the synthetics and seismic traces. Wells belong to the same architecture mode and have similar TDRs. The two-way travel time is shortest in the same depth interval of homogeneous-normal cycle mode compared to other architecture modes.
The azimuth of fractures and in situ horizontal stress are important factors in planning horizontal wells and hydraulic fracturing for unconventional resource plays. The azimuth of natural fractures can be directly obtained by analyzing image logs. The azimuth of the maximum horizontal stress [Formula: see text] can be predicted by analyzing the induced fractures on image logs. The clustering of microseismic events also can be used to predict the azimuth of in situ maximum horizontal stress. However, the azimuth of natural fractures and the in situ maximum horizontal stress obtained from image logs and microseismic events are limited to the wellbore locations. Wide-azimuth seismic data provide an alternative way to predict the azimuth of natural fractures and maximum in situ horizontal stress if the seismic attributes are properly calibrated with interpretations from well logs and microseismic data. To predict the azimuth of natural fractures and in situ maximum horizontal stress, we have focused our analysis on correlating the seismic attributes computed from pre- and poststack seismic data with the interpreted azimuth obtained from image logs and microseismic data. The application indicates that the strike of the most-positive principal curvature [Formula: see text] can be used as an indicator for the azimuth of natural fractures within our study area. The azimuthal anisotropy of the dominant frequency component of offset vector title seismic data can be used to predict the azimuth of maximum in situ horizontal stress within our study area that is located in the southern region of the Sichuan Basin, China. The predicted azimuths provide important information for the subsequent well planning and hydraulic fracturing.
Seismic fault surfaces are compulsory input for structure modeling that unravels the structural deformation history of the subsurface. Seismic fault attributes provide geoscientists with alternative images of faults. However, seismic fault attributes only highlight possible fault locations and do not directly provide fault surfaces that are required inputs for structural modeling. Interpreters construct seismic fault surfaces using interpreted seismic fault sticks on vertical seismic slices. Interpreting fault sticks on hundreds of seismic slices is time consuming. We have semiautomatically constructed fault surfaces by simulating the procedure of manual seismic fault interpretation. Our algorithm consists of three main steps: (1) obtaining fault sticks in the inline, crossline, and time slices; (2) grouping the fault sticks according to the connectivity and mutual exclusion (topology) between the fault sticks on the inline, crossline, and time slices; and (3) generating the fault surface patches by merging the fault sticks time slice by time slice through the topology analysis. Our algorithm contains one optional step: manually merging the fault patches if needed. We test our algorithm on open access seismic data and our workflow accurately generates fault surfaces for most faults including conjugate faults in the seismic data. Considering that it usually helps to weight the estimation according to the quality of the computed fault attribute, the algorithm computes fault parameters such as fault dip and strike using weighted principal component analysis.
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