Improving fracture performance through information collection and evaluation
DEVELOPMENT OF AN OPTICAL-BASED SINGLE-WELL SEISMIC SYSTEM (OSWS)
In the U.S., very large unconventional oil and gas (UOG) resources are found in shale deposits. According to a 2018 estimate in the Annual Energy Outlook 2020 by the Energy Information Administration (EIA), the volume of technically recoverable gas from gas shale is 2,829 Tcf—enough for 92 years of consumption at the 2018 level of 31 Tcf. EIA also estimates that in 2018, the U.S. possessed 44 Bbbl of technically recoverable shale oil.
However, production of these shale gas and oil resources is often very inefficient, with UOG oil recovery rates reported as being as low as 5% to 8%. Thus, a tremendous additional resource is available at known locations, if an improved recovery can be designed and implemented. The first step in this process is to generate better images that will lead to an improved understanding of these complex reservoirs.
The lack of a detailed understanding of the reservoir and production processes is currently creating a significant environmental impact that can be lessened while improving the economics of gas resource extraction. This can be accomplished by mapping the natural fractures in greater detail than what is possible today. It also can by accomplished by monitoring—at much greater resolution than is possible with today’s surface-based imaging technologies—the induced hydraulic fracturing and proppant distribution in the fractures, as well as the subsequent production.
It has been shown that seismology, using surface seismic sources and receivers, is technically able to image geology in 3D, albeit in low resolution, and monitor the production process using seismic data from surface seismic vibratory sources (VibroSeis). Thus, it is the resolution that is currently lacking.
It is well-established that if large volumes of high-quality borehole seismic vector data are recorded in vertical and horizontal boreholes, drilled to and into shale gas and oil reservoirs, the data can be used to image and monitor the reservoirs in 3D/4D, in higher resolution. Using borehole seismic receivers to record the data will improve the resolution by 2 to 4 times over the resolution provided by the surface seismic sources and receivers, since the seismic data only need to penetrate the near-surface attenuating formation once.
If the surface layer is avoided altogether by placing both the sources and the receivers in boreholes, then further improvement in the resolution, by a factor of 10–20X, is possible. This will lead to a step change in producers’ understanding of the oil and gas extraction process that is only possible by applying large arrays of advanced seismic mapping and monitoring technologies recording a full suite of high-quality seismic data.
The project’s approach, under the direction of William Fincham at NETL, to improve the UOG production process is to design, develop, and laboratory- and field-test, a more sensitive and more effective high- temperature seismic imaging and monitoring system, Fig. 1. Paulsson designs and builds fully operational prototype vector borehole seismic sources, which are engineered for deployment with seismic vector receivers in the same well.
Their single-well seismic system will detect very small changes in fracture properties and orientation; volumetric stress; pore pressure; fluid conductivity and types; proppant distribution; fluids; and saturation. The system also will be able to monitor and map passive seismic data from fracturing or fluid flow, as well as data from surface seismic sources. Vibratory seismic sources are preferred, since they couple non-destructive high-frequency signals much more effectively into the survey formation than impulsive sources.
The new borehole seismic system will allow deployment in both vertical and horizontal wells, Fig. 2. This is not possible with commercial systems today without using expensive and fragile well tractors for the deployment.
The new single-well seismic source-receiver system will have a bandwidth from 5 to 3,200 Hz, using active vibratory seismic vector sources, which will provide for much broader bandwidth data than available from any existing commercial or research seismic system. The receivers also will record microseismic data, extending the useful bandwidth to at least 8,000 Hz. The new all optical-based vector sensor system will be about 100 times more sensitive than geophone-based seismic systems.
The new system will deploy sensors with an 80-dB rejection of out-of-plane seismic energy, allowing for a precise location of reflections and microseismic events. The Fiber Optic Seismic Vector Sensor (FOSVS) system also will allow for source and receiver deployment in deeper wells, at higher pressures and temperatures than what is possible today. In combination, the new fiber optic-based seismic sensor and downhole seismic sources will record far-superior multi-component high-fidelity data, allowing for superior imaging, detection and location of all seismic events.
The downhole source and receiver system will also integrate Injectable Acoustic Micro Emitters (IAME) by Terves LLC into the overall seismic system. The development of IAMEs, together with the means to record the high-frequency seismic data that the IAMEs generate, will, for the first time, provide operators of UOG resources with a proppant tracking technology that potentially allows operators to calibrate and tune the hydro-fracturing, proppant injection and oil production processes. In turn, this significantly increases the recovery of the hydrocarbon resources.
Under this project, the Principal Investigator (PI) is developing a broad-bandwidth downhole seismic vibratory source that will be combined with existing FOSVS. The new source is designed to be clamped to the inside of the borehole wall, and generate and couple non-destructive seismic energy in three modes—Axial, Torsional and Radial—into the geologic formation. The three source motions will generate complimentary seismic wavefields, enabling the combination of 3C seismic sources with 3C optical accelerometers, thereby generating 9C seismic data. Together, the source and the receivers will be able to image vertical faults and salt domes, and monitor reservoir changes that are invisible to surface seismic techniques.
• The PI and TdVib (a partner in the project) are currently designing the full-scale, fully operational prototype of the downhole axial seismic vibrator. They expect that this prototype will be completed in Mid 2021 and undergo significant laboratory testing in Mid to late 2021.
• The PI and TdVib performed extensive modeling of several options for the downhole vibrator, leading to an understanding of the optimal size of the reaction mass and Terfenol actuator pre-load. The following parameters will be used going forward:
o Force Output: 10,000 N (2,500 lbf)
o Frequency band: (5 -3,200 Hz)
o Terfenol-D Rod diameter: 1.25 in.
o Terfenol-D Rod length: 6 in.
o Accelerated mass: 20 kg
• The PI performed a small field test, using the prototype Terfenol vibrator source and a small array of both 3C geophones and 3C FOSVS. The data recorded demonstrated that the energy from the Terfenol vibratory source with a force output of 1,509 N (339 lbf) can be coupled into the ground efficiently. The correlated signal-to-noise ratio from the vibratory 1,509 N (339 lbf) Terfenol seismic source matched the signal-to-noise ratio of a 50,000-N (11,240 lbf) impact source.
• The PI and TdVib successfully completed a laboratory bench-scale test of the Downhole Vibratory Seismic Source (DVSS) prototype in conjunction with the FOSVS and demonstrated the compatibility of the two technologies. The DVSS data were recorded using 5–1,600-Hz sweeps. The test compared the measurement of the PI tool and a standard geophone, finding that the FOSVS provided far superior data when used in combination with the DVSS.
• The concept design of the 3C downhole seismic sources was completed. The PI selects the appropriate high-temperature magneto-strictive material, which will be able to operate temperatures of 482°F (250°C) and at a well pressure of over 20,000 psi.
• The PI has designed and implemented the seismic processing system for the downhole seismic vibrator. It can use tailored custom sweeps and non-linear cross-correlation functions to assure a broad, flat spectrum of the recorded and correlated data.
• The project will model the performance of the three source actuators and how they interact with casings and the associated cement that couples the casing to the formation. It will use their finite element modeling system for this investigation.
• The PI has determined the environmental requirement for the seismic source actuators. This includes the temperature and pressure requirements, and the necessary lifetime of the system under harsh conditions in the borehole, including the presence of corrosive chemicals in the borehole fluids that the system must withstand. The developed actuator needs to operate in an environment up to 392°F (200°C) at a 20,000-psi pressure.
• The project also has determined the geophysical requirements for the seismic source actuators utilized in a high-resolution seismic system that records wide-frequency band, and high-fidelity data in wells with different casing programs. The developed actuator is projected to operate at frequencies between 5 and 3,200 Hz and be capable of generating a controllable, peak non-destructive force in excess of 10,000 N (2,500 lbf).
The clamped, multi-component, seismic vibratory source system has been designed, and an axial prototype has been built. The prototype downhole seismic source was tested in a laboratory setting and in a small-scale field test, achieving 10–1,600-Hz sweeps and a maximum force of over 339 lbf (1,509 N). The project expects to be able to achieve a force in excess of 2,500 lbf (10,000 N) in the same broad-frequency band during the next phase of the development project.
The PI has designed the borehole seismic vibratory sources to be deployed, using the same clamping system that secures its optical seismic vector receivers to the borehole wall, thereby effectively coupling the seismic energy to the borehole. This deployment system also has been shown to eliminate any tube waves, which is a critical capability for a single-well seismic system. The first source tested generates a borehole axial oscillating point force. Other directional seismic sources that will be included in the future will use torsional and radial source motions that generate complimentary radiation patterns. The new single-well seismic system has been designed to be deployed, using the Paulsson existing small-diameter drill pipe, so the sensor arrays can be deployed in vertical, deviated and long-reach horizontal wells. The source will be deployed on the same system concurrently with the receivers.
The power of vibratory seismic sources is two-fold. First, the time-distributed energy provides a low, instantaneous, non-destructive force, compared with impulsive sources, (i.e., low instantaneous stress), which enables an effective elastic coupling of the energy. This issue is particularly important, when the source is deployed in a high-cost borehole. Any source-induced damage to the casing-cement interface would render the borehole seismic source unacceptable to any oil and gas field operations. Second, the correlation process used during the processing of seismic vibrator data improves the signal-to-noise ratio by an estimated 40 dB. This improvement in the signal-to-noise ratio allows for a much longer-range detection of data transmission and reflection targets.
As noted above, this project is one of a number of projects either conducted internally by, or funded by, NETL. For more details on this, and related, projects, visit the NETL website at www.netl.doe.gov.
Disclaimer: “This project was funded by the Department of Energy, National Energy Technology Laboratory an agency of the United States Government, through a support contract. Neither the United States Government nor any agency thereof, nor any of its employees, nor the support contractor, nor any of their employees, makes any warranty, expressor implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.”
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