Nancy House

Fracture quality from integrating time-lapse VSP and microseismic data

Tight gas reservoirs are problematic to produce, often requiring multiple stages of hydraulic fracturing in order to create connected pathways through which hydrocarbons may flow. In this paper, we propose a new methodology to characterize the quality of hydraulic fractures. Using synthetic VSP and microseismic data, we test the concept that the rock volume containing open, gas-filled fractures will scatter seismic energy more profusely than a volume containing closed, nonproductive fractures. By measuring the amount of scattered energy in a time-lapse 3D VSP study taken before and after the hydraulic fracturing episode, we hope to compare the productive flow quality of different regions of the hydraulically fractured rock. The microseismic recordings allow us to locate areas which have been hydraulically fractured and create imaging operators to extract the scattered signals from the time-lapse VSP data.

Understanding Hydraulic Fractures in Tight-gas Sands through the Integration of Borehole Microseismic Data, Three-dimensional Surface Seismic Data, and Three-dimensional Vertical Seismic Profile Data: A Jonah Field Case Study

Completion techniques in tight hydrocarbon reservoirs commonly include hydraulic fracturing (fracing) to increase conductivity and improve deliverability. Because completion techniques are expensive, often costing as much as half of the cost of a well in tight formations, it is important to understand the factors that control the fracture geometry. Improved understanding of the fracs leads to better overall reservoir management by more accurately executed treatments, identification of bypassed resources, and optimizing infill well placement for maximum reservoir drainage. All disciplines associated with the development of the reservoir: drilling, completions, reservoir engineering, geology, and geophysics can benefit from increased understanding of the frac mechanisms and resultant fracture geometry. This Jonah field study illustrates the integration of several different data types: surface seismic data, vertical seismic profile (VSP), and borehole microseismic data to determine the magnitude and direction of induced hydraulic fractures in a complex, tight-gas reservoir.

Hydraulic fracture quality from time lapse VSP and microseismic data

The ability to produce from low permeability, tight gas reservoirs is directly tied to the ability to repetitively perform successful hydraulic fracturing in a series of closely spaced wells. The key question is whether the induced fractures remain open and permeable, which is in part a function of the stress field and the emplacement of proppant. We study the ability to detect and characterize hydraulic fractures from scattered seismic energy. A 3D VSP forms the reference for seismic reflectivity before hydraulic fracturing. During the hydraulic fracturing the microseismic events are recorded and then the arrival times picked and the events located. Another 3D VSP survey is recorded after the fracture treatment. The difference between the VSP surveys yields a 3D time lapse VSP dataset which contains the changes in the reflected wave field and the addition of scattered energy. The microseismic moveout times can be used to extract from the time lapse VSP data the seismic energy scattered from the induced fracture planes. We show the encouraging results from both model and field data.

Fracture quality images from 4D VSP and microseismic data at Jonah Field, WY.

Summary Natural and induced fractures provide the only means of production in tight gas sand reservoirs. The objective of this work is to locate and characterize natural and induced fractures from the analysis of scattered waves recorded on 4-D (time lapse) VSP data in order to optimize well placement and well spacing in these gas reservoirs. Using synthetic seismic data, we have previously shown that it is possible to characterize the quality of fracturing based upon the amount of scattering of seismic energy from hydraulic fractures. We show this concept applied to a field dataset from the Jonah Field in Wyoming. The time lapse (4D) VSP data from this field are imaged with a migration algorithm using shot travel time tables derived from the first breaks of the 3D VSPs and receiver travel time tables based on the microseismic and perf shot arrival times. We create images of the fracture planes through two of the hydraulically fractured wells in the field. The scattered energy shows correlation with the locations of the microseismic events and azimuthal scattering which is different from the azimuthal reflectivity of the reservoir. This gives us more confidence that we have separated the scattered signal from simple formation reflectivity. Variation of the scattered energy along the image planes suggest differences in the quality of the fractures in three distinct zones.

Integration of Surface Seismic, 3D VSP, and Microseismic Hydraulic Fracture Mapping to Improve Gas Production in a Tight Complex Reservoir

Summary Completion techniques in tight hydrocarbon reservoirs typically include hydraulic fracturing to increase permeability. In this study surface seismic data, 3D VSP data, and microseismic mapping of induced hydraulic fractures were combined to understand the magnitude, direction, mechanisms, and lithologic controls on hydraulic fracturing in a tight gas reservoir. Fracture points were mapped from 3D surface seismic data, VSP data were used to tie borehole measurements to the surface seismic volumes, and 3D VSPs and offset VSPs were used to increase resolution and determine specific influences of reservoir zones or faults on the direction and magnitude of the fractures. Detailed velocity information obtained from multi-level multi-component VSP data (measured with the same instruments as the microseismic events) provided accurate locations of the measured fracture events in addition to providing well-constrained ties to the surface seismic volumes. Integration between disciplines improved the reliability of all of the data and provided the interpreter a unique opportunity to ‘see’ where the induced fractures occurred, thus highlighting fluid pathways within the complicated reservoir. These insights significantly improved design and implementation of hydraulic fractures. The integration methodology can be applied in other settings and projects.

Design through interpretation of a very large 3D VSP in a complex area in Jonah Field, Wyoming

In the spring of 2005, EnCana Oil & Gas (USA) proposed the acquisition of a 3D VSP data set in a well later drilled in a complex compartmentalized portion of the Jonah gas field in Wyoming. Development of this area would benefit from the greater reliability of structural and stratigraphic interpretation enabled by the increased resolution of this 3D VSP. Figure 1 illustrates the acquisition geometry. Seismic data are recorded by downhole geophones at the center of ap-proximately 1400 source points. Surface source point signals are collected by a receiver array in the borehole. The resulting 6.5 mile2 survey was designed, permitted and acquired within a nine-month period in 2005. Innovative design and acquisition techniques led to successful acquisition on time and within budget.

Fracture Quality From Integrating Time-Lapse VSP and Microseismic Data

We present a new methodology to characterize the quality of hydraulic fractures by extracting the amount of scattered seismic energy from the induced fractures. A 3D VSP is collected over the field before and after the hydraulic fracturing is performed. Microseismic recordings of the hydraulic fracturing treatment form the basis for imaging operators. These imaging operators are used on the time lapse (difference) VSP volumes to extract the amount and angular variation in amplitude of scattered energy. Model results show that compliant, open fractures produce larger amounts of scattering than stiff, closed fractures. It may also be possible to use the azimuthal variation in scattered energy as an additional indicator of fracture compliance.

Economic Impact of Limited Three Dimensional (LTD) Seismic Acquisition in a Complex and Expensive Exploration Setting

Summary In geologically complex fold and thrust terrains, recording conventional 2-D seismic is often so expensive that exploration companies acquire the minimum amount possible, any more being economically difficult to justify. Under these circumstances 3-D seismic data is often perceived as financially unreasonable, especially in the exploration phase of an evaluation. Such was the case for Mobil and partners in the Amazon rain forest in 1996 in an area known to be structurally complex. Under these conditions Mobil executed a ’Limited [low fold] Three Dimensional’ (LTD) seismic survey. The incremental cost of acquiring the 128 km 2 LTD volume was approximately 5% of the cost of the conventional 2D data that was acquired to delineate the structure. Later interpretation of the volume resulted in decreased drilling costs, additional ‘proved reserves’, and better understanding of the complex internal structure drilled.