SR2020 has years of experience designing and conducting highly technical High Definition Borehole Seismic Surveys and processing the resulting images. Through our extensive connections in the upstream oil and gas industry we have also aligned ourselves with several groups of expert professionals and O&G software technology providers that we draw on to ensure that we bring the appropriate skills to the table to address fracture interpretation and analysis portions of the proposed program.
Project Design – during this initial phase of a FractureScan HD project we will work closely with our client to ensure achievable program objectives are established and any known constraints are identified. Once the program design document has been developed we can assist the client with procuring any of the data acquisition services that SR2020 does not directly provide. Alternatively, the client may choose to arrange for these services on their own.
Pre-Survey Modeling – the primary objective of this stage is to ensure that the program’s fracture imaging and mapping objectives are achievable and to optimize the receiver array and seismic source location configurations. SR2020 will obtain various well, log and subsurface information from the client in order to complete a detailed modeling of the anticipated seismic program. The results of this program will be reviewed with the client and form the basis of the detailed technical survey design requirements.
Survey Acquisition – this stage spans the full range of activities from the mobilization of SR2020 equipment and field crew to/from the client well site all the way through recording and QC on the final shot data in the field. In North America this stage typically spans a few days to a few weeks depending on the location, survey complexity and condition of the target well.
Seismic Processing – the processing of HD borehole seismic images and micro-seismic data is where SR2020, time and again, proves that we are indeed among the elite, truly world-class specialty seismic companies. Whether it is the care and attention that goes into the P/S velocity inversion work, extracting wave energy data or estimating fracture densities we are confident that our processing services routinely differentiate SR2020 as the leading HD borehole seismic provider.
Fracture Interpretation/Analysis – in many instances, we find that the interpretation of 3D VSP imagery is not a core competence within the client organization. In these instances we routinely provide clients with our initial interpretation of the data in order to help them “kick-start” their internal, more detailed review. In some situations, clients retain us to perform in-depth, detailed fracture analysis and related reservoir characterization.
Post Project Review – during this closing phase of the project we work closely with the client to review the outcome of the project and gauge them against the initial project objectives. We will also take the group through a brief but effective exercise to identify lessons learned and continuous improvement opportunities that will enhance the value of future FractureScan HD projects.
The only means of production in tight gas and shale gas reservoirs is through natural and/or hydraulically induced fracture networks. Being able to determine the location and volume of reservoir that is being accessed via these fracture networks is a significant challenge for tight/shale gas operators. If operators had the capability to more confidently and accurately identify the location and quality of these networks they could greatly improve their ability to optimize well placement and completion practices and thereby drive down lifting costs on a per MCF basis. Within many tight/shale gas companies, geophysical experts are being tasked with finding and developing additional methods of imaging and characterizing fractures. Micro-seismic mapping is one of the most common methods being employed to obtain valuable information during hydraulic fracturing operations as to the location, magnitude and timing of resulting seismic events. While micro-seismic mapping provides rapid results, there can also be a significant level of uncertainty around the precise location of these events and this method alone, does not provide any means of assessing the quality of the induced fractures.In the last couple of years, some testing of the application of time-lapse, high definition borehole seismic imaging methods combined with micro-seismic mapping has been done to both substantiate the micro-seismic results, as well as, to shed light on fracture quality. Early results from these tests have been promising. However, more work is required and at SR2020 we believe that with improved survey designs, higher fidelity acquisition systems and fine-tuned fracture detection data processing methods we can rapidly advance this combined fracture analysis/reservoir monitoring technique. At SR2020 we continue to push the boundaries of high definition borehole seismic imaging and we are currently in discussions with shale gas operators to gauge their interest in working with us to further develop such seismically-enabled fracture imaging/analysis methods.
Is a leading edge fracture analysis/reservoir monitoring technique that is at the field trial stage. This offering applies to unconventional tight and shale gas plays and addresses the following optimization goals:
The successful exploitation of a shale gas asset requires very dense drainage architectures (i.e., tight well spacing and extensive multi-point well completions). Typical drilling and completions spend can exceed $3-6 million/well.
In order to gain additional information to help further optimize overall exploitation programs, operators are also making significant investments (i.e., 100’s of thousands of $/well) in fracture monitoring and mapping methods. The potential to leverage this information to reduce the overall D&C costs of the program and/or increase the average long term well productivity by optimizing well and frac placement represents as much as a 10x return on the initial investment in gathering this information. However, the value of this information is being questioned as it is widely acknowledged that present fracture mapping methods are subject to significant uncertainty concerning fracture location, extent and estimated stimulated rock volume. They are also unable to detect pre-existing natural fracture networks. The combination of higher definition, time-lapse seismic imaging techniques together with micro-seismic mapping holds the key to a step change improvement in the detail and reliability of the acquired information.
As a result, forward-looking operators are starting to invest in evaluating new applications of proven technologies to increase their confidence in fracture analysis diagnostic information. SR2020’s FractureScan HD™ offering is designed to address this emerging market.
The characterization, imaging and analysis of fracture systems using seismic data is a constantly evolving field. In simple terms, the seismic response to the presences of fractures is a composite response due to:
These responses can manifest themselves in:
All of these key quantities can be effectively extracted from time lapse 3D vertical seismic profile (VSP) data. Therefore time-lapse 3D VSP’s are one of the principle technologies behind our FractureScan HD™ offering. This technology has proven to be useful in the characterization of both induced and natural fracture trends. Time-lapse surveys (pre and post frac) allow us to image subsurface regions that have been permanently affected by the hydro-frac operation. To achieve this, a time-lapse consistent pre-stack depth imaging processing flow is applied. This 4D information together with micro-seismic mapping data can be used to image regions in which open fractures cause significant scattering of seismic waves. Correlations between mapped events and time-lapse images can help differentiate between open and closed fracture networks.
Understanding the proposed techniques employed within FractureScan HD™ requires a brief description of some basic principles and a look at some previous ground breaking work done by others in this field. Let’s start by considering a simple VSP survey configuration and look at how seismic ray paths are affected when they travel through fractured rock. A set of fractures traveling through a well is shown in the diagram. The well is instrumented with an array of geophones that are deployed to be used in the acquisition of a 3D VSP survey. A simplified, but useful analogy is that the seismic response to fractures behaves like a stack of playing cards. They appear to be stiff when seismic waves encounter them perpendicularly and soft when waves encounter them parallel to the layering. Therefore the fast (S1) wave exhibits particle motion perpendicular to the layering and travels along the layering while the slow (S2) wave exhibits particle motion in the direction of the layering and travels perpendicular. The transmission rays emanating from the surface seismic sources carry information about fractures: primary waves (P, S1, S2) and converted waves (PS conversion). The reflection rays emanating from the subsurface also carry information about fractures: AVO and AVAZ. As a result, the following seismic data categories are useful in the analysis of fracture networks:
Some of the most compelling results along these lines were described recently by Lewallen (SEG 2008) to support his work on integrated seismic fracture characterization for a Piceance Basin fractured tight gas reservoir. Lewallen (SEG 2008) takes a variety of independent information and cross validates the individual observations into a consistent description of the fracture characteristics at this particular site. FMI, well log wave form sonics, laboratory core measurements, numerical models, borehole seismic and surface seismic measurements are analyzed in a comprehensive study to estimate the reservoir fractures properties and their expressions.
The figures below are reprinted with permission of Society of Exploration Geophysicists and show that the fracture induced anisotropy can be detected with borehole seismic VSP data from characteristic patterns in particle motions, characteristic amplitude and timing delays. Thus, they clearly indicate dominant fracture directions and fracture properties that are consistent with several other independent measurements, leading to realistic rock physics models and cross-calibrated, integrated data sets describing the reservoir fractures. More details can be found in the recently published paper as referenced below.
The body of research and pilot results in this field is slowly expanding, however we believe the following selected references provide excellent coverage of the field for those that desire a more detailed technical discussion of the proposed methods:
Program Design – In order to obtain the desired high definition seismic data, input data requirements are stringent and necessitate capturing repeatable, time-lapse seismic data with identical source and receiver positions. High frequency sources need to be employed and receivers need to be placed in a quiet borehole environment. A dense source layout guarantees sufficient coverage and Signal-to-Noise Ratio (SNR); a dense and long receiver array ensures the properly sampled capture of the seismic wave field. If micro-seismic information is to be used, the receiver well needs to be close enough to be able to record small events reliably. SR2020 developed our patented long receiver arrays to ensure that we could satisfy these demanding requirements, we have proven this capability through over 50 HD borehole seismic imaging projects throughout the world.
Because we deploy geophone receivers down-hole with high frequency seismic sources on the surface, we need to pay particular attention to the basic geometry which is largely dictated by the location of the wells relative to the specific reservoir volume we wish to image using VSP and monitor micro-seismic activity within. The geometry that determines the areal coverage of a 3D VSP image is shown in the neighboring diagram.
The primary image of a 3D VSP is a cone shaped image with roughly the proportions shown in the preceding diagram. However there are several imaging algorithms that SR2020 has developed that increase the image foot print or tailor the imaging to particular geological scenarios and can do that without having to consider the overburden.
The application of horizontal wells with multiple fracture locations has become the most prevalent form of drainage architecture employed in shale gas development projects and a growing number of tight gas developments.
In general terms, the deeper the subject reservoir is and the closer the fracture treatment zones are to the well(s) where the receiver array is deployed, the more desirable the data/cost relationship. The ideal situation would be closely spaced wells that are deep enough to allow us to both image and record micro-seismic events from one or more development wellbores. This would remove the need for observation wells to deploy the receiver arrays in. This coverage example is shown below.
Assuming a reservoir TVD of 5000 ft we would be able to image up to 2500 ft away from the wellbore. This being the case, we would be able to acquire baseline VSP data (VSP 1 & 2) in two of the development well bores prior to fracing. We would leave the receiver array in the second wellbore to acquire micro-seismic data during the fracing operations for the surrounding three wellbores within our effective data capture radius.
Following the fracing operations in the first three wellbores we would acquire a time lapse VSP (VSP 3) and then move the array to the first wellbore to monitor the final fracturing operations and then obtain the fourth and final VSP (VSP 4). This coverage allows us to monitor the entire subsurface drainage area efficiently with minimal disruption to the fracing operation, while ensuring that high-quality, repeatable seismic data are collected. The time-lapse effects are analyzed and can be directly calibrated with other limited frac performance data, essentially allowing us to see the stimulated rock volume of the entire drainage pattern.
Processing and Interpretation Sequence – There are a couple of ways that we will work with the combined VSP and micro-seismic data sets. In the first case, all of the 3D VSP data sets are imaged using an identical true-amplitude pre-stack depth imaging flow. The resulting 3D image volumes are differenced. Amplitude differences will indicate regions of potential scattering locations, indicating the existence of open fractures. Individual fractures are likely below resolution limits but fractured regions should be clearly visible.
These regions can then be extracted and visualized as reservoir objects using an industry standard 3D seismic interpretation package providing a view and dataset that can be easily cross referenced with other information commonly referred to by multi-disciplinary asset teams with G&G, D&C and Reservoir Engineering groups involved in analysis and optimization decisions.In the second case, we will use a high-resolution velocity model obtained from the VSP data to more accurately map the micro-seismic data into the subsurface reservoir volume.
Pre-stack data from both 3D VSP data sets are subtracted to isolate the scattering response induced by open fractures. Those differenced pre-stack gathers will then be imaged in the depth domain using wave propagation and velocity information obtained in the VSP together with scattering move-out derived from the micro-seismic event data. The scattering response record is thus imaged and large amplitudes at a particular subsurface location will help identify the existence of a strong scattering potential. This scattering potential is attributed to the formation of open fractures.
Regions demonstrating strong scattering potential will then be extracted and visualized as a second set of rezervoir objects. In particular, the micro-seismic event data can be cross-validated with the scattering potential reservoir objects to visualize differentiate between micro-seismic events that occured within regions that indicate either open or closed fracture networks. The figure on the left provides a rough indication of the envisioned output, in a 2D cross-section view.
We are convinced, that the quality and accuracy of the combined results will significantly higher that have been obtained in the past by employing the combination of a longer, higher reciever count seismic array and much denser seismic source layout.