The productivity of shale reservoirs can be greatly increased with a good understanding of natural fractures and geomechanics. Natural fractures are vital in enhancing the reservoir’s permeability, but natural fractures are not evenly spaced along the wellbore or within the reservoir. In addition, when natural fractures are present, the fracture permeability is controlled by pore pressure and stress and changes with time depending on the injection and withdrawal of fluids. Unfortunately, many stimulation stages result in non-commercial rates due to a lack of natural fractures or when natural fractures close due to stress. As a result, the recovery factor – the percentage of hydrocarbon produced – is extremely low, typically ranging from 6 to 12 percent of the resources in place.
We suggest two solutions to enhance the recovery factor in shale reservoirs: multicomponent seismic to determine the location of natural fractures and refracturing to open closed fractures or to expand the drainage area.
Shear-wave azimuthal anisotropy, an advanced seismic-based technology, is the best means of characterizing areas of high fracture density in shale reservoirs. As reported in Part I, this technology played an essential role in the early development of Silo Field and led to the first horizontal drilling program in the Rockies. Fracture identification and monitoring are crucial for optimal shale reservoir development due to heterogeneous distribution caused by local variations in elastic properties and stress conditions. Not understanding the complexity of shale reservoirs and the role of natural fractures can harm the bottom line and lead to economic failure.
Geophysics has previously taken a minor role in shale reservoir development, and that needs to change as the mantra of “one and done” leaves too much oil and gas in the ground. Technical advancements in seismic monitoring can help us develop shale reservoirs and reduce carbon emissions. The recovery factor can be tripled or quadrupled, given “smart” reservoir development. The added benefit is that the storage of carbon dioxide and utilization of methane provides the associated environmental upside necessary to develop these resources.
Multicomponent Seismic
Multicomponent seismic enables the recording of compressional (P) and shear (S) waves. The added benefits to full wavefield recording are several but, historically, have been costly and considered more “experimental.” That is about to change, given the evolution of receiver development. Nodal seismic systems now allow for up to 50,000 multicomponent receivers to be employed. One significant advantage of multicomponent is that you don’t need large offsets to record P and S data. Both electrical and fiber-optic receivers now allow for recording multicomponent data with high fidelity. Of the two, electrical receivers still have the edge in the recorded data resolution, but that might change significantly with the number of receivers employed in our surveys.
Another factor to consider is the availability of shear wave sources. Vibrators that can be used to induce horizontal ground motion are an endangered species. The main reason is that industry has yet to commit money to build these sources. Is that reason to abandon multicomponent seismology and stick with P-waves alone? No. A variety of sources can generate shear waves. The most realizable is the use of dynamite or vertical vibrators and the conversion of energy at acoustic impedance interfaces in the subsurface, which gives rise to converted shear waves. Other sources can be improvised, for example air blast from linear dynamite sources (primacord) that couples with the ground to impart a down-going shear wave. The evolution of multicomponent seismic technology is impressive and far from over.
The low recovery factor in horizontal wells can be attributed to two main reasons. Firstly, the initial hydraulic fracture stimulation was not optimized based on the location of natural fractures along the lateral. Secondly, the geosteering of wells missed many of the natural fractures, further contributing to the low recovery factor. The mantra in the early development phase was “pump and pray.” The industry reluctantly admitted that 30 to 60 percent of their fracture stages “worked.” That leaves 60 percent to 30 percent of the reservoir virtually untouched. How can we access that remaining part? The answer, in part, is to use seismic technology to assist in that quest. Can we go where we have gone before and have added benefits? Yes!
Fracturing and Refracturing
Shale reservoirs’ matrix permeability is so low that it can take several months for a methane molecule to travel just one meter through the matrix. During hydraulic fracture stimulation, natural fractures open and are filled with proppant. Other types of heterogeneity, such as bedding planes, can divert a portion of the fracturing fluid and create fracture complexity. These processes enhance the reservoir’s permeability by reducing the distance that hydrocarbon molecules travel through the matrix before they reach a high permeability conduit to the borehole.
However, the pore pressure decreases with production, increasing the effective stresses. Initially, the stress change causes a reduction in the fracture permeability, which reduces the production rate. Refracturing the same zone can often restore a percentage of the fracture permeability, leading to a higher production rate. With sufficient production, the direction of in-situ stress can flip, allowing the refracturing to propagate in a different direction and expose new rock for production, thus expanding the drainage area.
Refracturing has been widely used to increase production in vertical wells in the Codell Formation in Colorado. After refracturing, the production rate is similar to the initial stimulation, indicating the refracturing has exposed new rock.
Will this technique be effective in horizontal wells? We think so. Finite element geomechanical modeling in the Codell Formation shows a 90-degree stress reversal in the semi-depleted reservoir due to reduced pore pressure. Refracturing in this stress reversal volume will propagate a fracture into the adjacent unproduced formation and connect it to the existing wellbore.
Montney Case Study
RCP had the opportunity to work alongside Talisman Energy to explore using time-lapse multicomponent seismic data to develop the Montney reservoir at Pouce Coupe, Alberta. The insights provided were startling in that it was shown that only a tiny portion of the reservoir contributed to the flow of gas to the wellbores. Sure enough, the stages with significant production corresponded to the highest density of natural fractures. Armed with this knowledge, what can be said about the efficiency of the hydraulic fracturing process, and how can it be changed or improved?
The Montney Formation is a vast shale play in Western Canada and is still under development (figure 1). At Pouce Coupe, Alberta, Talisman Energy acquired a time-lapse multicomponent seismic program to investigate using multicomponent seismic data to monitor the hydraulic fracturing process of two wells. The setup for these time-lapse surveys is shown in figure 2.
In Talisman’s study, RCP worked with Sensor Geophysical, Calgary, to conduct amplitude variation with angle inversion of azimuthally sectored converted wave data to obtain proxy measurements of fast and slow shear wave volumes. The processing enabled a volume calculation of the shear wave splitting parameter. A 2-D line extracted along the two boreholes is shown in figure 3. If this baseline survey could have been conducted before the drilling of the wells, it could have led to better well targeting of the naturally fractured areas. Nevertheless, one can anticipate that the better-producing well is the 2-7 well based on the amount of contact with the more highly fractured reservoir volumes that the well intersected.
The advantage of conducting time-lapse multicomponent seismic in conjunction with hydraulic fracturing is that the stimulated reservoir volume (SRV) can be documented. Figure 4 shows the volume changes in response to the hydraulic fracturing operations in the two horizontal wells. It is important to note that hydraulic fracturing in naturally fractured media is not a near-wellbore phenomenon. Stresses affect crack opening and closing over large distances. Fractured rock is easier to break than the “country” rock, and designing hydraulic fracturing programs to optimize this breakage can be conducted best if you know where the naturally fractured rock is in the first place. Shear wave-splitting volumes can provide the necessary information to get the most out of the hydraulic fracturing process and reduce costs.
Notice that the greater stimulated reservoir volume is associated with the 2-7 well versus the 7-7 well. Does this additional SRV result in better production? The answer is a resounding yes (figure 5).
Wattenberg Case Study
Wattenberg Field has been the site of horizontal well development in the Denver Basin since 2008. The current focus is the development of the Niobrara and Codell Formations. Reserves in the field are enormous, but recovery is low.
Can we learn more about these two formations’ recovery processes by conducting time-lapse multicomponent seismic surveys?
RCP partnered with Anadarko Petroleum, now OXY, to conduct 9-C time-lapse seismic surveys. The area of investigation is one square mile in which 11 wells were drilled, seven in the Niobrara and four in the underlying Codell. Different borehole spacings and completion schemes were targeted for the Niobrara. Multicomponent time-lapse seismic surveying was conducted to see if the SRV could be determined (figures 7 and 8).
The wells were drilled and a baseline 9-C seismic survey was conducted with P- and S-wave vibrators. The survey was conducted to ensure a full fold over the one square mile Wishbone section. A monitoring survey was conducted before putting the wells on flow back and production. A couple of months occurred between the baseline and monitor survey.
Figure 9 shows the time-lapse azimuthal shear wave anisotropy for the two zones. The SRV for the Codell is twice that of the Niobrara C zone. A planimeter indicated that 60 percent of the Codell was accessed versus 30 percent of the Niobrara C. The highest productive areas occur on the west side of the section where the natural fracture density is higher, the wells more closely spaced in the Niobrara, and the well completions involved higher volume treatments. We further recommended that wells be drilled at a 400-foot spacing in the Niobrara B and C layers and that completion diversion occur near the faults. The Niobrara consists of chalks and marls and is very heterogeneous. Due to the heterogeneity, there are ample opportunities for refracturing in the Niobrara as the SRV is low, even with borehole spacing at 400 feet and up to 36 fracture stages per well. Moreover, the Niobrara is prone to the closure of the natural and hydraulic fracture system, which represents the greatest SRV. Closure stresses are high due to tectonic forces in the region and the wells’ pressure drawdown.
Where should the new fracture treatments be applied? Logically, one would think in the areas that weren’t accessed in the first place. A safer bet is to reopen the areas of natural fractures that were opened in the first place and inject more proppant. Opening the natural fracture system is relatively easy and can occur over large distances as the natural fracture network is extensive. Keeping it open is the major problem. We know from decline curve analysis how quickly these wells decline.
The Opportunity
The opportunity exists to double, triple or even quadruple production from our shale reservoirs. Doing so will take new integrated technologies and people willing to employ these technologies. Of course, economics will remain the driving factor, but oil prices above $50 a barrel in shale development can provide a substantial economic upside. Key to this new development will be seismic monitoring. New tools are being developed to facilitate the use of multicomponent seismic data for monitoring at different scales.
In addition, where the fracture density is high or can be increased through refracturing, we can employ carbon dioxide injection, which could significantly increase the oil recovery from shale reservoirs while providing safe storage of this greenhouse gas. Recoveries where this concept has been tested have increased the recovery factor above 20 percent and doubled the reserves in the field.
Read Part One of this series.