Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. VSP receiver stations are positioned vertically at increments of approximately 50 ft (15 m). This small spatial sampling allows all wave modes (downgoing, upgoing, shear, compressional) to be separated from the raw data.
Gao, Yongde (CNOOC Zhanjiang) | Chen, Ming (CNOOC Zhanjiang) | Du, Chao (CNOOC Zhanjiang) | Wang, Shiyue (CNOOC Zhanjiang) | Sun, Dianqiang (CNOOC Zhanjiang) | Liu, Peng (Schlumberger) | Chen, Yanyan (Schlumberger)
Drilling in Ledong field at Yinggehai basin of South China Sea faces challenges of high-temperature and high-pressure (HTHP). The high pore pressure and low fracture gradient results in a narrow mud weight window, especially when drilling close to overpressured reservoir. Well LD10-C was the first exploration well targeting at reservoirs in Meishan formation. Well LD10-A and LD10-B were offset wells in a distance of 15-20km drilled for reservoirs in Huangliu formation, which is above Meishan formation. During drilling, both wells encountered severe gas kick, mud loss and did not reach target.
In order to drill and complete well LD10-C safely, a real-time pressure monitoring solution was introduced with integration technique of logging while drilling (LWD) and look-ahead vertical seismic profile (VSP). It helped to monitor pore pressure and fracture gradient while drilling and predicted top of the overpressured reservoir. This enabled to keep the mud weight and equivalent circulation density (ECD) within a safe margin to avoid kick and mud loss, helped to set casing as close as possible to the top of reservoir. The reservoir section was drilled with a manageable mud weight window.
The main achievements of this task were: 1) accurately monitor and predicted pore pressure coefficient at reservoir. The predicted pore pressure coefficient was 2.25 SG versus 2.24 SG from actual measurement. 2) accurate prediction of reservoirs top. The predicted top depth of Sand C was 2m error with accuracy of 0.05%. The top depth of Sand D was 10m error with accuracy of 0.2%. 3) 12.25in section and 8.375in section was successfully drilled deeper with pressure monitoring. The 9 5/8in casing was set 491m deeper and 7in line was set 80m deeper than plan. As a result, well LD10-C was drilled and competed without any drilling complexities.
This was first application of LWD and VSP together for pressure monitoring while drilling in Yinggehai basin. The successful completion of well LD10-C confirmed that this integrated solution was an efficient technique to predict and reduce drilling risks, optimize mud weight and casing diagram, improve operational safety and save cost in HTHP offshore drilling.
Distributed acoustic sensing (DAS) is a rapidly evolving fiber optic technology for monitoring cement curing, perforation performance, stimulation efficiency, and production flow and, more recently, for performing vertical seismic profiling (VSP). VSP data can be acquired and processed to determine velocity models that are used in surface seismic imaging for reservoir characterization, or for microseismic monitoring of hydraulic fracturing operations. The limitation of conventional VSP data acquisition has been well accessibility, with wireline-conveyed tools deployed during openhole or casedhole logging campaigns before well completion or during workovers. Fiber optic cable conveyance by coiled tubing (CT) expands the opportunity for VSP data acquisition during planned CT interventions. This paper presents an example of a CT DAS VSP acquisition. The processing steps are shown to overcome some of the noise challenges inherent in CT DAS data, such as persistently strong borehole tube waves induced from the surface operations activities. A case study is shown for the depth tie between surface seismic data and the CT DAS VSP derived corridor stack image, demonstrating the viability of CT deployed fiber to acquire DAS VSP data.
Ferla, Maurizio (Eni) | Miranda, Francesco (Eni) | Nutricato, Giacomo (Eni) | Galli, Giuseppe (Eni) | Moriggi, Sara (Eni) | Malossi, Alfio (Eni) | Guglielmo, Carmelo (Eni) | Tesconi, Marcello (Eni) | Mangione, Alessandro (Eni) | Stocchi, Donatella (Eni) | Naouar, Aymen (Eni) | Bettinelli, Pierre (Schlumberger) | Manai, Nabil (Schlumberger) | Slail, Osama (Schlumberger) | Pagnin, Andrea (Schlumberger)
Efficiency is a key factor on any operation. In this paper, we introduce the heterodyne Distributed Vibration Sensing (hDVS), which is an innovative technology based on fiber optic system to improve the duration of borehole seismic operations.
We designed a survey aimed at comparing standard downhole geophone accelerometers measurements to i) optical fiber seismic installed inside the hybrid Wireline cable and ii) optical fiber clamped permanently to the well completion tubing. This comparison was conducted using a standard rig source VSP in association to advanced Offsets VSP. The purpose of the study was to evaluate this innovative technology and to assess the feasibility of drastic operation time reduction without compromising output data quality.
To better evaluate the readiness of the technology, we decided to compare three distinct types of downhole measurements and designed a specific advanced acquisition which allowed us to compare various configurations. Consequently, the borehole seismic acquisition performed in the MR-SE1 well located in Makhrouga field (Tunisia) was split into two phases. Phase #1: during open-hole Wireline logging, using the standard downhole geophone accelerometers (VSI) and fiber optic seismic cable (single-mode cable) installed inside the Wireline logging cable (called hybrid Wireline cable). Phase #2: at the departure of the drilling rig, using a fiber optic seismic cable (single-mode cable) installed permanently along the intelligent completion. The results highlight the effectiveness of the hDVS technology with a proven decrease on operation timing, with reliable and good SNR recorded data.
Nowadays, efficiency is a key requirement for any data acquisition process. The heterodyne Distributed Vibration Sensing (hDVS) is an innovative technology designed to achieve such effectiveness by making the Vertical Seismic Profile (VSP) a matter of minutes instead of hours, as using standard downhole equipment, without compromising output data reliability and allowing the measurements repeatability (no well interventions required).
Finally, based on the quality of the dataset acquired, further analysis can be conducted for imaging purpose by analyzing the reflected waveforms, which could bring additional information and could change the way we are operating.
Luo, Qiang (Key Laboratory of Shale Gas and Geoengineering, Institute of Geology and Geophysics, CAS and University of Chinese Academy of Sciences) | Wang, Yibo (Institute of Geology and Geophysics, CAS) | Chang, Xu (Institute of Geology and Geophysics, CAS) | Zeng, Rongshu (Institute of Geology and Geophysics, CAS) | Zheng, Yikang (Institute of Geology and Geophysics, CAS) | Wang, Yongsheng (China Shenhua Coal to Liquid and Chemical Co., Ltd.)
Baseline and repeat VSP surveys were conducted by Shenhua CCS (Carbon Capture and Storage) demonstration project in Ordos Basin, China. A complete workflow of time-lapse VSP monitoring method was presented in this paper. Wave field separation and consistency processing, two key techniques in time-lapse VSP data processing, worked well. The upgoing P wave was used to image timelapse profiles by the VSP-CDP stack. Comparing the results, it was found that the time-lapse VSP method provides accurate and high-resolution images to monitor the CO2 diffusion range. The reliability of the method was then checked by the lithology of the target layer. With this current time-lapse VSP and geological analysis, the results showed that there is no obvious danger of gas leakage in the project, and that CO2 has been sealed in five predetermined reservoirs.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 204C (Anaheim Convention Center)
Presentation Type: Oral
Summary From well planning to well execution, the record breaking Mississippi Canyon 822#14 3D Vertical Seismic Profile (VSP) at the Thunder Horse Field in the Gulf of Mexico has been extremely valuable for overcoming resolution challenges and bridging illumination gaps in the surface seismic data. The VSP has been influential in key decisions, such as future well targeting, calling total depth (TD) of hole-sections in a challenging Pore Pressure/Fracture Gradient (PPFG) environment, and framing volumetric upside & downside potential for future wells. The VSP accomplished its primary goals of providing a high-resolution image compared to surface seismic and proving the viability of Independent Simultaneous Source (ISS) technology for future offshore VSPs, a potential huge cost savings for future acquisitions. The key uncertainties targeted by the well bore survey were thin beds below detection and sub-seismic faults. Additionally, the unique acquisition geometry of the VSP provides illumination uplift over surface seismic that is negatively impacted by current infrastructure and the salt canopy, which overlies approximately one third of the Thunder Horse South structure.
As Distributed Acoustic Sensing (DAS) systems advance, increasing amounts of 3D/4D DAS-VSP (vertical seismic profile) data are being acquired. These large amounts of DAS data are used to diagnose and update velocity models and improve the quality of sub-surface images from both borehole and surface seismic data. In this study, we developed a simple, robust, and practical tool to diagnose azimuthal variations of velocity model uncertainties using 3D DAS-VSP data. We use 2211 seismic shots on 8 rings centered at a receiver to calculate apparent velocities (Vapp) using an initial model (Mod) and an updated model after tomography (Tom). Relative misfits between observed and model calculated Vapp reveal azimuthal variation in velocity model uncertainties.
The effect of anisotropy on sonic measurements within layered formations has an impact in geomechanics and geophysics workflows. A new single-well workflow is presented that uses a probabilistic approach using prior information to provide a complete continuous characterization of the transverse isotropic (TI) parameters. The workflow applies to any well orientation or structural dip and yields results that are consistent with prior information from offset wells, core measurements or walk-away vertical seismic profile (VSP) results.
Analysis of single-well sonic measurements is predominately done using deterministic models for which the orientation of the measurements must be aligned with the layering; in other words, vertical or horizontal (not deviated) wellbores must be used for flat structural dip. In addition, such models depend on strict assumptions for using the measurements to predict the missing parameters because there are not enough measured slownesses in a single well to determine the five independent moduli. Multiwell models depend on variable well orientations, usually where a combination of a vertical with multiple deviated wells are needed to characterize the relative change in slowness with dip for each associated slowness. Often, the acoustic anisotropy must be determined before these deviated wells are drilled and evaluated to impact well placement, drilling design, or stimulation plans.
The approach demonstrated herein uses prior information of TI elastic properties to determine a consistent model at each depth. The inversion uses all sonic slownesses, compressional, fast and slow shear, as well as Stoneley shear along with the fast shear azimuth and density to provide a continuous output of either stiffness moduli or velocities at each depth. The prior information can be from multiple sources such as core tests (dynamic or static), borehole seismic survey results, offset well data, or a public core database.
A case study from an offshore field in Abu Dhabi, UAE, is presented to demonstrate this new workflow using sonic and walk-away VSP data for input to velocity model calibration for prestack depth migration. Understanding the impact of anisotropy on wellbore stability calculation for adjacent fields is also of interest.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 205A (Anaheim Convention Center)
Presentation Type: Oral
Suprajitno and Greenhalgh (1985) used contour-slice filtering in the FK domain to separate up-going and down-going wavefields to facilitate vertical seismic profile (VSP) data processing. Berkhout (2014a; 2014b; 2014c) exploited the wavefield separation idea by directly resorting to a Bremmer's series-like concept in the modeling engine and so proposed two new seismic imaging technologies, namely full-wavefield migration (FWM) and joint migration inversion (JMI). Liu et al. (2011) pointed out the origin of the low-frequency noise in reverse-time migration (RTM) images and then proposed an imaging condition, based upon wavefield separation, to suppress such low-frequency noise. Fei et al. (2015) and Wang et al. (2016) used wavefield separation by double Hilbert transformations to remove false structures in RTM images. Zheng et al. (2018) used double Hilbert transformations to do up/down separation of wavefields in 3D forward modelling. To our knowledge wavefield separation has been limited to either vertical or horizontal propagation directions, and the industry lacks a general theoretical framework that is capable of handling wavefield separation at an arbitrary propagation direction. In this abstract we show that with the input data properly organized, FK filtering is capable of separating wavefields at an arbitrary propagation direction. We design this FK filter explicitly, and mathematically show that wavefield separation via double Hilbert transformations is equivalent to using the same FK filter.
Distributed acoustic sensing (DAS) technology offers full-well seismic sensor coverage for borehole seismic applications. With DAS channels in a horizontal well, it becomes possible to compute horizontal local slowness directly from a walkaway vertical seismic profiling (VSP) survey. Combining the vertical slowness computed from a vertical well, the slowness vector provides a measurement to detect and determine local anisotropy around the well. This paper presents a model-based study to explore the feasibility of using DAS walkaway VSP to determine local anisotropic parameters for a medium of vertical transverse isotropy (VTI). A field dataset was also tested for the effectiveness of the methodology. Results of this study demonstrated challenges in local slowness extraction and anisotropy estimation. With a combination of vertical and horizontal wells (or the vertical and horizontal parts of a lateral well), the slowness vector can be obtained in a layer of homogenous medium. The accuracy of anisotropy estimation depends on the availability of the vertical DAS cable and heterogeneity of the medium around the well.
Presentation Date: Tuesday, October 16, 2018
Start Time: 9:20:00 AM
Location: Poster Station 16
Presentation Type: Poster