Pe Unit Vi.docx

Unit-VIII: WELL SEISMIC SHOOTING FOR VELOCITY DETERMINATION & VERTICAL SEISMIC PROFILING Well Seismic Shooting for Velocity Determination  Vertical Seismic Profiling (VSP)  Borehole Tomography  Checkshot Survey WELL SEISMIC SHOOTING FOR VELOCITY SURVEY INTRODUCTION Seismic surveys can be divided into surface seismic surveys and bore hole seismic surveys. The principle is the same for both except that, in surface seismic, the source and receivers are positioned on the surface or close to it, whereas, in borehole seismic, sources are typically located at the surface and the receivers are located in the well. Typically dynamite and vibrators are used in onshore and airguns are used in offshore bore hole seismic surveys. The borehole seismic record is recorded by the geophones placed in the borehole. A seismic source positioned on surface is triggered to produce a wave that propagates into the earth as direct waves from the surface source and as downgoing multiples and it returns back toward the surface as primary reflections and upgoing multiples. The record contains information about the reflection and transmission properties of the Earth, and its coverage depends on the survey and the structures near the well. The classifications of borehole seismic applications are summarized in Table 1.0A and the benefits of borehole seismic are as follows:  The integration of spatially extensive surface seismic surveys with vertically sampled logs and other well data helps to understand the reservoirs. Borehole seismic surveys uniquely forge this link by quickly providing high-resolution, calibrated answers for drilling & development decisions.  The borehole seismic provides vital depth and velocity parameters to surface seismic surveys, matching seismically imaged layers to precise borehole depths.  They provide high-resolution images that extend hundreds of meters around the wellbore and into the inter-well volume.  Provide structural & stratigraphic information  Help to monitor fluid movement  Predict lithology and rock or reservoir properties when calibrated with logs, core, production data, or other information

The problem addressed in seismic modelling, or simulation, is calculating the seismic response (travel time and amplitude) for a given stratigraphic model. The stratigraphic model consists of those physical properties that influence seismic wave propagation—typically compressional wave speed, shear wave speed, and mass density. This set of parameters can describe the simplest possible solid, called an isotropic elastic solid. For some purposes, it is sufficient to consider the earth as an acoustic (fluid) medium characterized by only two parameters: sound speed (v) and mass density (ρ). Seismic reflections are generated where there is a contrast in impedance (which is the product of velocity and density). Depth-dependent velocity and density models are needed to identify events or to create a synthetic seismogram. Velocity information can obtain from a variety of sources:  Vertical Seismic Profiling (VSP)  Borehole Tomography  Checkshot Survey  Sonic Log with Checkshots  Sonic Log VERTICAL SEISMIC PROFILING (VSP) A vertical seismic profiling (VSP) is effectively seismic surveying using boreholes, yields the best connection between geologic horizons and seismic events. It is recorded by using a source at the surface and many receiver locations down a wellbore, or vice versa. The receivers record full traces for interpretation. The term offset is used to describe the horizontal distance between the source and receiver. The VSP method utilises both the downgoing wavefield as well as the reflected and / or diffracted wavefield to provide additional information about the zone imaged by the method. VSP gives actual travel-times from the surface to points in the earth, and it is the best and most direct method of associating seismic events with geological horizons. An added advantage of the VSP method is that it can utilise shear waves as well as primary waves.

Most VSPs use a surface seismic source, which is commonly a dynamite or vibrator on land and an airgun in offshore or marine environment. VSP is recorded in essentially the same way as a checkshot survey. The major difference between a VSP and a checkshot survey is that VSP data are recorded at much smaller spatial sampling intervals than checkshots. While a receiver may be moved a vertical distance of 200´to 1000´ (61 to 305 m) between checkshot levels, it should be moved no more than 50´ to 100´ (15m to 30m) when recording a VSP. Specifically, the vertical distance between successive VSP traces should not exceed one-half of λmin, where λmin is the shortest wavelength contained in the recorded VSP wavefield. When a seismic wave field is recorded with this small spatial sampling interval, several processing techniques can be used to separate the down-going and upgoing wave fields. Once the up-going wave field is isolated from the more dominant down-going wave field, the up-going reflection events can be properly analyzed and interpreted and used to produce improved imagery of the subsurface. There are different types of VSP configurations which are discussed below:  THE STATIC VSP The survey used string of detectors at a fixed position with a single shot at the surface (Figure 1.1B-I).  ZERO-OFFSET VSP If the receiver is directly below the source, the recorded data are called a Zero Offset VSP (Figure 1.1B-II). It is relatively inexpensive. A zero-offset VSP is sufficient for event identification and 3-D seismic calibration. In a flat-layered earth, the reflection points associated with a zero offset VSP occur close to the vertical line passing through the source and receiver coordinates. Thus, the image made from these data will illuminate the subsurface in only a narrow vertical corridor passing through the receiver location. However, if there is structural dip, the reflection points associated with a zero offset VSP can occur at significant horizontal distances from the vertical line passing through the source and receiver. When properly processed, such data can produce high resolution images extending from the receiver position to the farthest reflection point coordinate.  OFFSET VSP If there is a significant horizontal distance between the source and receiver, the recorded data are referred to as an Offset VSP (Figure 1.1B-III). In offset VSPs, reflection points are always distributed over some horizontal distance, so offset VSP recording geometry is often used to produce seismic images that traverse portions of a reservoir near survey wells.  SINGLE LEVEL WALKAWAY VSP In this type of survey, shots are fired into one downhole detector from source points with increasing distance from the well head (i.e. walking away from the borehole) (Figure 1.1B-IV).

 MULTI-LEVEL WALKAWAY VSP In this type of survey, shots are fired into a string of downhole detectors over a wide range of depth levels from source points with increasing distance from the well head (i.e. walking away from the borehole) (Figure 1.1B-V).  WALKABOVE VSP A typical VSP survey carried out to accommodate the geometry of a deviated well, also known as vertical incidence VSP. In this survey each receiver is in a different lateral position with the source directly above the receiver for all cases. Such data provide a high resolution seismic image of the subsurface below the trajectory of the well (Figure 1.1B-VI).  DRILL-NOISE OR SEISMIC WHILE DRILLING VSP Drill bit noise is used as borehole seismic source and receivers are placed in the surface.  There are also multi-offset and multi-azimuth VSPs, which use many source locations. These are much more expensive and sometimes are useful for local, high-resolution imaging. Some other VSPs are proximity VSP are shear wave VSP.

BENEFITS OF VSP SURVEY  Provides greater vertical and lateral spatial resolution than surface seismic. This technique produces a high-resolution, 2D image that begins at the receiver well and extends a short distance (a few tens of meters or a few hundred meters, depending on the source offset distance) toward the source station.  This image, a 2D profile restricted to the vertical plane passing through the source and receiver coordinates, is useful in tying seismic responses to subsurface geologic and engineering control.  Seismic to Well Tie up can be possible  Improves velocity analysis for surface seismic processing with an accurate velocity model  3-Component geophones capture all wave modes providing Shear and Compressional images. Provides rock properties / pore pressure indicators Q Estimation, AVO Calibration and Anisotropy parameters to enhance Surface Seismic resolution  Provides high resolution images and attributes beneath and away from the well for inter-well reservoir imaging  High Resolution Imaging for reservoir boundaries, salt flank imaging, and fault identification in complex areas  Provides best geometry to fully image near wellbore formations, and correlates to 3-D surface seismic

BOREHOLE TOMOGRAPHY The borehole tomography, also known as hole-to-hole, cross-hole or cross-well seismic profiling (CSP) is an advanced method of borehole seismic surveys. Two or more holes can be used simultaneously, the source is deployed at various depth levels in one borehole and the receiver is placed at several depth stations in other borehole(s). The basic configuration of CSP survey is shown in Figure 1.2A.

The benefits of borehole tomography or CSP are as follows:  The raypath lengths between source and receivers are known and that by measuring the travel times along these paths the average velocity along each can be determined.  Any zones with anomalous velocity lying in the imaged plane between boreholes can be identified.  Along with determination of P- and S- wave velocities, Poisson’s Ratio and relative attenuation can be determined from the survey data.  Images made from the survey data have the best spatial resolution of any seismic measurement used in reservoir characterization because a wide range of frequencies is recorded.  CSP data are useful for creating high-resolution images of inter-well spaces and for monitoring fluid movements between wells. However, a CSP image is also a 2D profile with the image limited to the vertical plane that passes through the source and receiver coordinates. CHECKSHOT SURVEYS Surface-recorded seismic data often comprise the largest database that must be dealt with in reservoir development. However, seismic data have one shortcoming that can limit their usefulness—the reflection events used to map the seismic sequences and the seismic facies that describe the areal and vertical distributions of reservoir and sealing units are measured as functions of seismic travel time, not as functions of depth. To understand reservoir performance, the boundaries of these units need to be mapped in depth. Thus, the concept of the velocity checkshot survey has been developed to establish time-depth calibration functions at control

wells so that surface-recorded seismic images can be reliably converted to the depth images that are needed to do reservoir volumetric calculations. The purpose of a velocity survey is to produce a down-going seismic wavelet at the surface near a well and then to measure the time required for that wavelet to travel to a known depth where a seismic receiver is positioned in the well. This borehole receiver is locked successively at several different depth levels, and the vertical travel time to each level is measured. Each measurement of the source-receiver travel time is a checkshot, and the compilation of all of the travel time measurements into a time-depth calibration function is referred to as a checkshot survey (Figure 1.3A&B).

The source—receiver geometry used in onshore velocity checkshots is shown in Figure 3.1A. If possible, the energy source should be the same as that used to record the surface seismic data near the well. A buried explosive charge is shown in this diagram, but other common onshore energy sources include vibroseis or air guns operated in a water-filled pit near a well. Offshore, essentially all checkshot surveys involve air guns as the seismic energy source. Ordinarily, the borehole receiver is first lowered to the deepest checkshot level, and the travel time to this deepest receiver position is measured for one or more surface shots. The receiver is then moved upward a distance of 200, 500, or 1000ft (61, 152, or 305m) to record the checkshot, or vertical travel time, at successively shallower levels. The time-depth calibration function and velocity analyses that can be calculated from checkshot measurements are more reliable if each source-receiver travel path is a vertical straight line rather than an oblique, refracted path. Consequently, if a well is deviated, then the surface position of the source should be readjusted each time the downhole receiver is moved to a new depth level, as shown in Figure 3.1B, so that the travel path always remains as vertical as possible. Offshore, the vertical travel time to a receiver is defined relative to sea level. Since the energy source is below sea level when it produces the down-going wavelet, an amount of time equal to the air gun depth divided by the sound velocity in water is added to the measured time to adjust it to a sea level origin. Onshore, an arbitrary depth coordinate is chosen as the time datum. In Figure 3.1A, the datum is above the shot depth, and in such a case, the vertical distance between the shot depth and the datum depth is divided by the velocity in that interval. That time

adjustment is then added to the measured travel time to each receiver. If the depth datum is below the shot depth, as in Figure 3.1B, this adjustment time is subtracted from the measured traveltime. When a checkshot survey well penetrates formations that exhibit complicated structural dips, it is advisable to position an energy source on both the updip and downdip sides of the well so that two different travel time measurements are acquired at each receiver depth. One of the travel paths is usually a better approximation of a straight line than the other. In surveys where the structure is simple horizontal layering but where significant lateral velocity variation occurs, it is also advisable to record travel times from shots on opposite sides of the well and average the times so that the checkshot values are not biased with a velocity that is unrepresentative of the prospect area. When there is sufficient velocity and dip information and adequate pre-survey preparation time to allow ray trace modelling of the source—receiver travel path, it is helpful to calculate and display the anticipated ray paths for several possible source and receiver locations to determine which source position produces the best approximation of a straight line travel path to each desired receiver location. A checkshot survey is like a baby VSP. The receivers are sparsely located down the well, usually on key geologic boundaries. Also, the information recovered is limited to arrival time (a number) unlike the full trace a VSP gives. The checkshots help correct for any drift in a sonic log due to missing log intervals or hole problems. This makes the calculated travel times more reliable.