Wide-azimuth seismic enables better shale play economics

In North America a good deal of E&P technology effort is turning toward the previously unfamiliar territory of shale oil and gas plays and how to exploit this huge resource most effectively. This has largely come about as a result of advancements in horizontal drilling and hydraulic fracturing that have prised open enormous untapped reserves. Estimates vary, but the latest from the US Energy Information Administration in April suggests a total resource for US shale gas of 482 Tcf, which is less than earlier optimistic assessments but still enough gas to potentially see the US becoming a net exporter over the next decade.

The impact of this unexpected domestic renaissance in the US oil and gas industry has not emerged without its share of challenges – economic, technical, and environmental. Economically the industry has been almost too successful for its own good, with supply overtaking demand and reducing the market price of the commodity. Technically, hydraulic fracturing on this unprecedented scale is still something of an unknown quantity. And environmentally, public suspicion of the fracturing process shows no sign of abating, headlined by fears over potential well failures, water supply contamination, and earthquake hazards.

These are all issues geoscience can help to address and offer some practical business solutions. Wide-angle, wide-azimuth 3-D seismic surveying over shale reservoirs can be an extremely cost-effective preliminary stage of any shale development. The payoff is that it can provide geoscientists and engineers with important keys to understanding rock properties of the target subsurface and likely stress characteristics. Both have a direct bearing on the well placement, productivity, and safety of any hydraulic fracturing strategy. This type of mapping is particularly valuable as stress scenarios are likely to bring variations and have been shown to change within the space of a few hundred meters, most likely requiring adaptation of the fracturing program.

FIGURE 1. Minimum horizontal stress is shown within the Second White Speckled shale (2WS), a subunit of the Colorado shale. The inset at well locations is the vertical stress. (Images courtesy of CGGVeritas)

These wide-azimuth seismic surveys also have the potential to be repeated at any time during the production phase to monitor stress changes as a result of hydraulic fracturing operations and reservoir drainage.

Knowledge of the stress state prior to drilling also is useful to predict areas at risk for wellbore failure; in other words, drilling problems can either be prepared for ahead of time or bypassed altogether.

Economic value of seismic surveys

The value of estimating the principal stresses and rock properties for a reservoir using wide-azimuth 3-D seismic data can be seen from a survey in the Second White Speckled shale in central Alberta, Canada. The 3-D wide-azimuth seismic survey was shot over a small 9-sq-km (5.5-sq-mi) area southeast of Red Deer, Alberta, in the Western Canadian Sedimentary basin. The target area was the Cretaceous Colorado shale group, which sits above weak shales of the Joli Fou formation and sandier Lower Cretaceous Mannville formation. The Mannville formation sits above an unconformity below which the strata consist predominantly of carbonate rocks.

Results showed that about one-quarter of the shale in the survey area would fracture as a network, while the majority of the remaining shale would fracture linearly or not at all. Such information is extremely valuable when considering the placement of wells and the optimal location to initiate fractures. If only three-quarters of the prospect is susceptible to fracturing, then there is scope for significant cost savings.

FIGURE 2. The map view of minimum horizontal stress over the Second White Speckled shale shows a significant change in stress. At well location 14-13 the stress is 20 MPa, and at well location 6-13 the stress is 26 MPa. This stress change occurs within the length of an average lateral well. The red line depicts the location of the vertical section in the previous figure.

Taking one well per square kilometer as the norm to develop this shale gas play, nine wells would need to be drilled at a cost of US $8 million per well, for a total of $72 million. Findings indicated that two fewer wells needed to be drilled to cover the reservoir, a savings of $16 million, for a total of $56 million. Such savings easily pay for the acquisition, processing, and analysis of the seismic data providing the relevant information. Other financial benefits accrue from being able to drill and complete the most prospective areas first, and there is the additional value of being able to use the seismic data in the planning of field-scale development.

Planning considerations with seismic surveys

In the planning of an optimal hydraulic fracturing program, four geomechanical factors need to be taken into account: brittleness, closure pressure, proppant size, and volume. The first two of these can be estimated between existing wells based on familiar concepts such as Young’s modulus and Poisson’s ratio, which can be derived from seismic data inversion.

FIGURE 3. In this characterization of fracture types over the Second White Speckled shale derived from a crossplot of DHSR and Young’s modulus, green suggests where fracture swarms will form, red suggests where the rock is more ductile and less likely to support fracturing, and yellow regions suggest where aligned fractures will form. Plots such as these can be used to high-grade prospective regions within a 3-D survey.

Brittleness is fairly self-explanatory. In the survey example, the Second White Speckled shale unit was found to be the most brittle part of the Colorado shale group. Closure pressure is defined as the pressure at which a fracture effectively closes without proppant in place.

Wide-angle, wide-azimuth seismic data allow estimation of all principal stresses by using a simplification of Hooke’s law and linear slip theory. An additional consideration is that well pressure must first overcome the hoop stress created in the rocks around the borehole. Hoop stress is the additional tangential stress in the rock close to the borehole wall that is induced by the presence of the borehole. It can be estimated once the principal stress estimates from the seismic data are known.

In situ stresses are clearly the most important factor controlling hydraulic fracturing. When the rock is subjected to long-term strain in geotechnical tests, static moduli are estimated from the slope of the stress-strain relationship. It follows that the moduli related to hydraulic fracturing are most likely the static moduli because hydraulic fracturing takes some time to build up the pressure required to fracture the rock.

In situ stresses can be estimated from seismic data. If it is assumed that the rocks in situ in the subsurface are constrained horizontally, i.e., the horizontal strain is zero in their natural state, and that the rocks are undergoing elastic deformation, then the in situ stress state of these rocks can be estimated from elastic information.

Elastic information is derivable from seismic data via amplitude vs. offset inversion, and the in situ stress state can be estimated from anywhere where seismic waves are reflected from the rocks at a wide (>40°) angle, hence the use of wide-angle, wide-azimuth seismic.

One of the most useful parameters for determining how a reservoir is likely to fracture is differential horizontal stress ratio (DHSR). As a rule, it is preferable if the ratio is low. When the DHSR is high, hydraulic fractures will tend to occur as nonintersecting planes parallel to the maximum horizontal stress since fractures tend to be created parallel to it. However, with a low DHSR, fractures induced by hydraulic fracturing will tend to spread in a variety of directions and intersect. This multidirectional fracture network provides much better access to the hydrocarbons in the reservoir.

FIGURE 4. In this composite plot of DHSR and Young’s modulus, platelet size is related to the magnitude of DHSR, and their orientation is aligned with the maximum principal stress direction. The other colors relate to values for Young’s modulus with hot colors depicting higher Young’s modulus, implying more brittle areas. The area indicated as “sweet spot” arises since the DHSR is low (platelets are small) and Young’s modulus is high.

The optimum scenario for hydraulic fracturing occurs where high brittleness and low DHSR are encountered. A crossplot of these values should indicate areas that are suitable for the creation of fracture networks. The result of applying this crossplot to the Second White Speckled shale formation of the Colorado group is shown in figures 3 and 4. The zones and cutoffs in the crossplot should be optimized through well control as the field is developed. Areas where the DHSR is low and Young’s modulus (brittleness) is high (green in the figure) are confined to small areas of this already small survey. These areas should be targeted first for drilling, thereby moving the best production prospects forward and increasing net present value.

Indicators for optimal hydraulic fracturing vary over very short distances. For example, the southwest of well 14-13 in the north-central part of the figure shows a change from a very good area for hydraulic fracturing to a bad area over a distance of less than 200 m (656 ft), much shorter than the length of most horizontal wells drilled in these plays. The results also indicate that most of the Second White Speckled shale will fracture with parallel fractures.

There are numerous pointers that can be derived from wide-angle, wide-azimuth seismic data to assist hydraulic fracturing programs. It is worth noting that the method is applicable in any play where hydraulic fracturing is being considered and where stress or geomechanics are an issue. The seismic data should be used to extrapolate information derived at well bores to the interwell regions.

This analysis can be done without well information using measured seismic velocities and assumed petrophysical relationships. Once principal stresses are estimated, other useful stress estimates such as hoop stress can be used to predict how the well will behave while drilling and under stimulation. Such is the tremendous amount of information on stresses and rock properties that can be estimated from wide-angle, wide-azimuth 3-D seismic data.