Tuesday, April 9, 2019

Borehole Seismic Data

Seismic surveys in the borehole deliver a high-resolution quantitative measure of the seismic response of the surrounding reservoir. Although these measurements may be used alone to image local features, they may also be tied with well data-logs and cores- and then related to more extensive surface seismic data. Advances in borehole geophysics are helping realize the full potential of existing data to create a sharper image of the reservoir. 

It's a matter of resolution. Surface seismic surveys deliver  one of the few quantitative measurements of reservoir properties away from wells, making the technique central to structural mapping of the entire reservoir volume. However, surface seismic waves cannot resolve features smaller than 30 to 40 ft [9 to 12 m] . On the other hand, logs and cores resolve features on the scale of a few feet down to about 6 inches [15 cm]. Reconciling these two measurement scales to get the optimal picture of the reservoir volume is a problem that has long challenged the industry.

Borehole geophysics has a foot in both the logging and surface camps. From the vantage of the wellbore, seismic data often have higher resolution than their surface seismic counterparts. Depths of each borehole receiver are also known, providing a better tie to the formation properties provided by petrophysical, core and other in-situ measurements and relating them to the 3D seismic volume. 

The idea of locating a receiver downhole and a seismic source at surface is not new. For more than half a century, the check shot has helped to correlate time-based surface seismic surveys with depth-based logs. Check shots check the seismic travel time from a surface shot to receivers at selected depth intervals. Subtraction of times, combined with the depth differences, yields vertical interval velocities and thus relates well depths to surface seismic times. 

In vertical seismic profiles (VSPs), the spacing between downhole geophone levels is considerably closer than for check-shot surveys. VSPs use high-quality full waveforms that include reflection information rather than just the time of first arrivals - or first breaks- to create an image of reflections near the wellbore. Building on this technique, 2D reflection images have been obtained by offset and walkaway surveys with sources and receivers in a variety of configurations that address most reservoir problems.

Yet, despite these and other developments, borehole geophysics has for many years failed to gain the status in reservoir characterization that some industry specialists think it deserves. Now, thanks to improved quality and increased confidence in the match between borehole and surface seismic data, borehole geophysics seems to be moving into an increasingly valued position.

Before examining how borehole seismic data are being used to successfully integrate other data, this article will illustrate how the scope of VSP is broadening through the development of horizontal, 3D and through-tubing techniques.

Broadening the Scope of VSP Applications

In the deviated and horizontal wells of the North Sea,the most common type of borehole seismic survey is the vertical-incidence VSP. These are often called walk-above surveys because, as the geophone is moved along the deviated section of borehole, the source is kept vertically above it, "walking above" the well.  In VSP terms, a horizontal well is an extreme version of a deviated well. Like other VSPs, deviated well surveys may be used for locating the well in the 3D surface seismic volume and assessing the quality of surface seismic surveys. Also, the technique may be employed for measuring lateral velocity variations and for imaging faults and structures below the wellbore. 

The following example of a walk-above VSP was carried out in late 1994, in a North Sea well with a 1.2 kilometer horizontal section. There were two main objectives. The first was to measure a suspected lateral velocity anomaly that may have been creating artifacts in the surface seismic data. The second was to obtain a high-resolution seismic image below the deviated portion of the well. An additional objective was to obtain seismic image in the horizontal part of the well.

Data were collected in ther vertical and deviated portions of the cased well using the conventional wireline-conveyed ASI Array Seismic Imager tool. In the horizontal section, a two-element CSI Combinable Seismic Imager geophone array was run on drillpipe in combination with a cement bond log. By decoupling the sensor module from the body of the CSI tool, the geophones are isolated from noise and distortions created by the drillpipe. 

As with any survey, the desired seismic image is produced using the reflected, or upgoing, wavefield. So the first processing task was to separate downgoing waveforms from upgoing. For walk-above surveys in horizontal wells, this is far from straightforward, since unlike vertical and deviated wells, there is no apparent time difference across the array between the downgoing and the reflected upgoing waves. It is therefore impossible to use conventional techniques to distinguish between reflections and downgoing waves. To improve the image a number of special techniques were used, including:
  • multichannel filtering to attenuate noise and sharpen the desired signal
  • downgoing wavefield subtraction using a long filter length to estimate the downgoing wavefield
  • median filtering techniques to estimate and subtract the energy scattered by faults
  • enhancement of the desired upgoing signal
  • equalization of the reflected wavefield amplitudes from the horizontal and the build up sections.

The final image showed three important features: the two faults marked A and B, which appear where suspected in the reflected image, and the dip of the strata below the well. Formation MicroScanner data acquired during openhole logging were compared with the VSP, confirming the fault locations-seen as chevrons in the VSP - and the apparent dips.

In this case study, VSP processing was performed before Formation MicroScanner data were ready to interpret, and the VSP helped the interpretation by outlining the major features. The two data sets were then interpreted and refined together, providing a more complete description of near-well geology than was otherwise available. The results met the main objectives of the survey and delivered an image below the horizontal section. 

An alternative strategy for acquiring and processing horizontal VSP data exploits the different responses of geophones and hydrophones to differentiate downgoing energy from upgoing energy in horizontal wells. Geophones are clamped to the formation, and sense its motion. In contrast, hydrophones are suspended in the borehole fluid and are sensitive to fluid pressure changes as seismic wave passes in any direction. When the two sensor types show the same signal polarity for a downgoing wave, they show different polarities for the upgoing wave.  By taking the difference between signals received at the two types of sensors - for a signal consisting of a direct pulse followed by a reflected pulse- the direct wave is canceled and the reflection enhanced.

Complications arise from differences in the coupling and impulse responses between geophones and hydrophones. However, this approach has recently been applied in the field, enabling the extraction of related wavefields in a horizontal well and the imaging of reflectors below the receivers.

 3D VSPs

VSP imaging surveys, such as walkaways, have been used for a number of years to image structural complexity away from the borehole. These walkaway profiles are essentially two-dimensional, confined to the vertical plane containing the surface source and the borehole. 

Because of the proximity of the receivers to the target, like all VPSs, these 2D images usually have the advantage of being of higher resolution than their surface seismic counterparts. But, by definition, 2D walkaways don't describe the full volume of the reservoir. Fortunately, the acquisition principle may be extended to cover three dimensions by repeated profiling in parallel lines - in effect, by collecting a series of 2D walkaway surveys similar to marine 3D seismic data acquisition. 

The progression from 2D to 3D in VSP surveys is similar to the progression in the surface seismic technique , and offers equivalent benefits. Thus, 3D VSPs allow high resolution imaging to augment surface 3D surveys and make it possible to obtain  images beneath surface obstacles, such as platforms, and near-surface obstructions, such as shallow gas zones. In addition, because the acquisition conditions and processing steps of VSP surveys are accurately reproducible, 3D VSP opens up the possibility of time-lapse, or 4D, seismic surveying. 

However, progressing from 2D to 3D substantially increases the need for planning and logistics control. Similarly, the processing requirements are almost an order of magnitude greater. 

The first 3D VSP survey was run in 1987 in the Adriatic Sea Brenda field, operated by AGIP. Since then, there have been two 3D VSP surveys in the Norwegian Ekofisk field for Phillips Norway- where a large gas plume over the center of the structure prevents imaging using conventional 3D surface seismic techniques. Other Norwegian surveys probe the Eldfisk and Oseberg fields. 

In the UK North Sea, a 41-line, 3D walkaway VSP survey has been carried out in Shell Expro's Brent field. In this case, the aim was to acquire a survey with improved resolution compared with the 3D surface seismic survey. The image was then be used to produce an accurate structural map to aid the planning of horizontal development wells in the Brent slump- a crestal zone of complex faulting and collapse which contains a significant portion of the field's remaining oil reserves. 

The survey was executed from a well with a trajectory that allowed positioning the geophones to give three-dimensional illumination of the slump zone. The receivers consisted of five shuttles with fixed triaxial sensors, clamped 2000 ft [606 m] above the target during the entire survey. Once in the well but prior to shooting, the coupling between each of the shuttles and the formation was evaluated using internal shakers to ensure distortion-free data.

The seismic source consisted of a cluster of three 150 in 3 sleeve guns. To supply sufficient gas for 41 lines of 200 shots per line, four 5100 cubic meter nitrogen-filled tube skids were used. Simultaneously with the downhole data acquisition, each shot location on the surface was recorded using two differential GPS navigation system. 

To make the survey cost-effective, it was vital to minimize time spent acquiring data -every extra minute per sail line meant an additional 41 minutes of rig time. For example, to reduce the time the vessel took to maneuver between lines, a strategy was devised to wrap each line efficiently into the next. In the end, the data were acquired within the planned survey time of two and a half days, including a conventional VSP.

The 3D processing involves an extension of methods already developed for 2D walkaways-data preparation and navigation check, triaxial projection, wavefield separation, deconvolution and migration. 

In this case, the processing consisted of separate preparation and processing of all 41 lines up to the deconvolution stage. Then all 41 reflected energy profiles were accessed by the 3D VSP migration algorithms to place the reflections correctly in space.

The successful processing of these surveys required an experienced geophysicist with strong interpretative skills to make the correct decisions at each stage of the processing -for example, to ensure that all possible questions related to the influence of data quality had been resolved. These skills ensured that the image was interpreted in terms of reservoir structure without processing artifacts.

The migration process requires the computation of raypaths from each source and every receiver to every reflection point in the subsurface. The rays are traced through a velocity model of the subsurface that can vary in complexity between flat layers ( a 1D layercake) to complex structures in 2D or 3D.

For simple structures , a layercake velocity model, which reduces computation time, is sufficient.  However, using this model in more complex subsurface may lead to erroneous positioning of reflections and the incorrect focusing of real events. More complex velocity model increase the number of ray-trace computations required, but are better able to position reflected events and focus the wave energy.

The Brent structure varies in the dip direction but changes very little along strike. Consequently, the velocity model is more complex than a plain 2D model but not as complex as a full 3D model; the structure varies in one horizontal direction and is extruded into the other horizontal dimension to form a so-called "2.5D" model. In this, the volume may be thought of as filled with an infinite number of 2D sections. This allowed computational efficiency due to symmetry and ensured a close match with the actual Brent structure.

Shell concluded that the Brent 3D VSP improved vertical resolution and significantly improved horizontal resolution- resolving features on the order of 100 to 150 ft [ 30 to 45 m] as opposed to the original 3D surface seismic resolution of 200 to 300 ft [60 to 90 m] . The interpretation of the slump features has confirmed conclusions reached independently , demonstrating the technique's potential and reducing the risk of a proposed new 3D surface survey.

 Through-Tubing VSPs

The third application broadening the scope of borehole geophysics is the VSP through tubing. Thanks to hardware developments, cost-effective VSPs can be run in mature fields that promise significant economic benefits

Traditionally, borehole seismic surveys are acquired in exploration wells when they are drilled. However, in older fields, borehole seismic information is often needed to aid the reservoir engineer in areas where no new wells are planned, or to plan a new well. Now a slim seismic receiver may be deployed by a simple masted logging truck to acquire borehole seismic data through production tubing and inside casing during workover or while the well is still on production. This reduces acquisition costs and makes surveys in multiple wells possible during the same mobilization. 

In this way, a full range of borehole surveys may be carried out and the data may be used to tie log and production information to new 3D surface seismic surveys being run in older producing fields.

The slim seismic tool has a 1 11/16- inch outside diameter and may carry one single-axis geophone group or three orthogonally mounted accelerometers.The mechanicallytt actuated anchor has a maximum opening of 7 in. [17 cm] . The tool is adapted for operation with a monocable wireline and through-wellhead pressure fittings. This allows for operations in producing wells with surface pressure. As with any system, a range of seismic information may be obtained in vertical or deviated wells, from check shots to walkaway VSP images.

For example, an offest VSP survey was acquired through tubing and through casing in an abandoned wwell in an inland shallow water field in south Lousiana, USA, using a marine vibroseis unit as a source to acquire high-resolution data. The offset VSP survey was designed to confirm the location of a low-angle fault-indicated by logs-which could not be seen on the surface seismic images. The fault's orientation was needed to reduce the risk of an infill development well and was easily spotted using the offset VSP image.

Using Borehole Geophysics to Integrate Data

A the heart of developments to improve data integration is the recognition of the complementary nature of some measurements. Perhaps the best example of this is the relationship between sonic logs and seismic data. In these two measurements, the physical interaction with the reservoir is the same, but at a different scale of resolution. The sonic tool measures formation compressional slowness, which is dependent on many factors, including the formation porosity and lithology. 

Compressional slowness combined with density provides the one-dimensional acoustic impedance of the formation, the same property that underlies seismic reflections. 

But seismic waves are sensitive only to relative changes in acoustic impedance, unlike sonic slowness measurements, which sample absolute values. Therefore, acoustic impedances from logs provide sufficient information to model most, but not all features of the seismic response. The total travel time measured by sonic logs is a required contribution to the bulk response of the low-frequency surface seismic surveys. Then, synthetic seismograms may be constructed and the response of the formation simulated by altering parameters such as porosity, fluid type and lithology. The synthetics can be used to interpret real data.

Although the scope of VSPs is expanding, the wealth of information relating to lithology, fluid contacts and the seismic responses that they produce is not always used to its fullest extent. This is particularly true when it comes to evaluating and improving the information content of surface seismic data. Now, existing technologies are being used in new ways to provide additional direct quantitative mesurements of the seismic response of the reservoir adjacent to wells.

The next two examples clearly indicate how the integration of all available data may improve understanding of the reservoir. The first example looks at how structural and stratigraphic interpretations may be improved. The second shows how reflection amplitude variation with offset (AVO) from VSPs may be used to calibrate surface seismic AVO.

Morgan's Bluff

In the Morgan's Bluff field of Orange County, Texas, USA, the operator IP Petroleum needed to map the shale edge of its Hackberry reservoir to design a secondary reservoir program.

Substantial existing 2D surface seismic data did not adequately image the reservoir. Therefore, vertical incidence and offset VSPs were shot within a production well. These results were combined with logs and geologic information to map the edge of  the shale. Further, the surface seismic lines were reinterpreted, resulting in an extensive remapping of the Hackberry sand.

The aim was to drill a sidetrack from the shut-in producing Well 8 toward the adjacent Well 10, depending on the exact reservoir boundary, to be determined using the VSP - the Hackberry sand was originally mapped on the strike line that runs through both of these wells.

First , the feasibility of this plan was tested and detailed survey models were constructed using structure maps, log data from the two wells and velocity data from a third well. Borehole seismic data shot in 1986 in the central part of the field were used to construct the general velocity model. In Well 8, sonic logs were available to about 8000 ft , and only nuclear and resistivity logs from there to total depth. A pseudosonic log was constructed from these logs and compared to the velocities from the VSP survey. A synthetic offset VSP was then generated using the same wavefield separation, deconvolution and migration processing to be used with the real data. 

Two scenarios were forward modeled: a gradual shaling out and an abrupt, or faulted, sand termination. From this it was agreed that in either case the shale boundary should be interpretable to within 100 ft using the offset VSP sections, and the go-ahead for the survey was given. Additionally, a second offset VSP to the west of well 8 was designed to confirm the interpretation. A VSP was also to be carried out in Well 8 to build an updated velocity model for migration.

The three downhole surveys were acquired with sources located 4000 ft [1212 m] to the west-southwest, 4300 ft [1300 m] to the southwest and 400 ft [121 m] to the east-southeast. An eight level downhole receiver system was deployed to record 110 levels at 50 ft [15 m] spacing from 8500 to 3000 ft [2575 m to 909 m]. Across each interval, the top and bottom shuttles were overlapped to check for any source amplitude, signature or phase changes during the survey.

Following a standard processing sequence using a flat-layer velocity model and some small velocity changes to match the model to the observed transit times, each of the offset VSPs was migrated. Logs from Well 8 were correlated with the offset VSPs.