September 8-12, 2019
BOOTH # 137
September 8-12, 2019
BOOTH # 137
Mestayer, J., Cox, B., Wills, P., Kiyashchenko, D., Lopez, J., Costello, M., Bourne, S., Ugueto, G., Lupton, R., Solano, G., Hill, D. and Lewis, A., ‘Field Trials of Distributed Acoustic Sensing for Geophysical Monitoring’, Pages 4253-4257, SEG Annual Meeting, San Antonio, TX, USA, 2011
OptaSense have installed a 40km system in New Zealand to monitor traffic on State Highway 1 running north out of Auckland. This paper, published by the end customer, discusses the advantages a DAS system offers for traffic monitoring and describes the aims and goals of our ongoing relationship with them.
Offshore brownfield exploitation generally involves operating in remote, environmentally sensitive areas that have geologic basins with complex overburden, structure and stratigraphy.
In these geologically challenging areas, Ocean Bottom Node (OBN) seismic acquisition is the technology of choice for a number of reasons; the most important being its ability to capture a high quality seismic image, which is critical for characterizing time-lapse response of the reservoir.
Due to the high acquisition cost, many mature reservoirs using an OBN approach for time-lapse imaging are surveyed several years apart, resulting in the missed opportunity to effectively manage and understand the reservoir.
To eliminate this risk, a supermajor operating in the Gulf of Mexico contacted the OptaSense team with the goal of identifying a low-cost alternative that would enable comparable or better quality seismic surveys at more frequent intervals.
Technology plays crucial role in providing the information to make sound exploration decisions. Given the complexity and high cost of deepwater development, there is great value in being able to identify the best spots to drill wells and manage production methods for field exploitation. This skill hinges on generating an accurate picture of the subsurface. Seismic technology lies at the heart of this process and was a key research priority for our client.
Vertical Seismic Profiling (VSP) has long been considered a possible solution for deepwater seismic imaging; however, high cost and practicality have made it unfeasible for many operators. Since the introduction of Distributed Acoustic Sensing (DAS) VSP technology, these concerns have essentially been eliminated.
Concept testing for the low-cost, on-demand DAS-VSP solution included several aggressive objectives, one being surveying reservoirs lying below thick salt formations which are notoriously challenging to image. Additional objectives included demonstrating repeat DAS acquisition using multimode fiber, acquiring DAS on active production and injection wells, and providing quick on-demand service for time-lapse monitoring of sweep efficiency.
To meet these objectives, OptaSense recommended running their DAS-VSP borehole seismic acquisition service, capable of acquiring 2D, 3D and 4D VSP data, and the fourth generation ODH-4 DAS interrogator unit (IU) for its unmatched imaging and measurement performance.
The ODH-4 provides a 6 dB improvement in signal-to-noise ratio over its predecessor—delivering the highest fidelity VSP measurements available. In addition to higher quality seismic imaging, the ODH-4 offers increased sensitivity, finer spatial sampling (1.02m) and finer spatial resolution of (4.02m gauge length) to capture high-caliber image resolution.
Oil and gas is commonly trapped subsalt, or near salt flanks.Incidentally, imaging near and below the large salt structures is naturally problematic for any surface or OBN seismic program. One of the best known methods to properly image these areas is a VSP survey, which enables access to these obscure locations. However, these wellbores commonly have high deviation and high entry to access costs, making the use of conventional geophones unfeasible.
The ODH-4 IU instead transformed the operators existing fiber optic cable attached to production casing into an array aperture to acquire VSP data across the entire wellbore.
By retro-fitting our DAS technology to pre-existing multimode fibers, OptaSense provided permanent, on-demand DAS-VSP access at no extra cost to the operator. Although DAS was originally developed for single-mode fibers, most legacy fiber optic installations are multimode.
By continuously pioneering the evolution of DAS technology, OptaSense has proven quality DAS measurement can be acquired on either single-mode or multimode fiber—enabling on-demand acquisition of quality seismic surveys from wellbores with existing fiber.
With OptaSense DAS-VSP borehole seismic acquisition service, the operator successfully acquired VSP data on actively producing and injecting wellbores during acquisition operations. Such a practice would be unthinkable with geophones.
In some cases, a mature field may not have suitable placement for, or the existence of, an observation well. This can impact an operator’s ability to monitor production, as well as optimize future well placement. Our DAS-VSP eliminates the requirement of observation wellbores for VSP imaging, while providing on-demand, direct monitoring of production and injection zones.This ensures operators receive the subsurface insight required to control current operations and optimize future placement of injector and producer wells.
OptaSense DAS-VSP also provides the ability to acquire data on active wellbores without shutting in operations—resulting in greater VSP imaging coverage at favorable economic costs.
Due to cost, 4D VSP acquisition at shorter intervals may not be feasible. However, the OptaSense DAS-VSP service is flexible, quickly mobilized and offers favorable economics for repeat acquisition monitoring.
Through the use of our DAS-VSP 4D time-lapse service, the operator effectively monitored conditions throughout the reservoir over time—increasing recovery, optimizing cost, reducing risk and extending the life of the field.
Manned operations for recording instruments can amount to significantly increased risk and cost depending on the duration and location of the program. Through the use of a suitable internet connection OptaSense can provide unmanned VSP services through remote monitoring of OptaSense equipment and data. This significantly reduced cost and HSE exposure for our client by reducing lodging, substance and day rates for an onsite operator, in exchange for a daily remote monitoring fee.
The quality of the DAS-VSP acquired using our ODH-4 IU surpassed our client’s expectations. This included data collected on multimode fiber, actively producing and injecting wellbores and those positioned subsalt.
Imaging objectives for 4D reservoir monitoring continues to be successfully met and our client is looking forward to expanding DAS-VSP service for regular time-lapse monitoring of their asset. In just a short period of monitoring, our client is moving forward with DAS-VSP service as an integral part of sustainable field development. They have realized added value with the service’s seamless application and the capability to remotely monitor the equipment and program. Our client highly advocates the installation of fiber optic cables for new offshore wells, and utilizing existing fibred wells to take full advantage of DAS for VSP acquisition.
OptaSense, a QinetiQ company, announces a collaborative research agreement with the Stanford School of Earth, Energy and Environmental Sciences that includes the installation of an on-campus fiber optic seismic array.
Using OptaSense distributed acoustic sensing (DAS) technology to sense ambient noise and seismic energy, the seismic array will enable scientists to conduct research in passive seismology. Located adjacent to a major geologic fault zone, the San Andreas Fault, the seismic array will be used to image subsurface properties that provide scientists a better understanding of the complex geology in the Bay Area.
The seismic array will leverage a two kilometer long, standard telecommunications fiber optic cable. The OptaSense DAS system will transform this fiber into thousands of distributed sensors capable of detecting changes in pressure, temperature and strain. A single fiber can create a seismic array with thousands of channels, allowing for dense sampling of seismic wavefields and the ability to detect weak signals.
Utilizing a Coherent Optical Time Domain Reflectometer, or Interrogator Unit (IU), the OptaSense system sends laser pulses down the length of the fiber to measure and observe changes in the backscattered light, indicating movement in the earth adjacent to the fiber.
In addition to enabling research in seismology, the OptaSense DAS system will support potential studies in fields such as structural engineering, communications, infrastructure monitoring, and security.
“Collaborating with one of the world’s foremost academic institutions is particularly exciting for OptaSense. For the first time, we are putting our DAS technology into the hands of the academic community and working with them to explore new applications and techniques. Through this collaboration we will be able to mature the understanding and expand the capabilities of DAS for the benefit of the wider seismic community,” commented David Hill, Chief Technology Officer at OptaSense.
OptaSense, a QinetiQ company, and its partner Optilan, a telecommunications systems integrator, have been awarded the combined leak detection and security package from ABB, the Engineering, Procurement and Construction prime contractor for the delivery of the control infrastructure* for the Trans-Anatolian Natural Gas Pipeline (TANAP).
The contract, in excess of $30 million split evenly with Optilan, was awarded at the start of the year and now enters the equipment delivery phase, marks a significant milestone for OptaSense, the global leader in Distributed Acoustic Sensing (DAS) and Optilan, an international communications and security systems provider. This will be the world’s largest fibre distributed sensing project, protecting and monitoring more than 1850km of pipeline, including perimeter security for all facilities.
The TANAP natural gas pipeline runs from Azerbaijan through Georgia and Turkey to Europe. The project is of strategic importance for the region, as it will enable the first Azerbaijani gas exports to Europe, while strengthening the role of Turkey as a regional energy hub. Construction of the pipeline began in 2015 and is scheduled to be completed in 2018, with expected costs in the region of $10-11 billion.
Magnus McEwen-King, Executive Director at OptaSense commented: “This project marks a significant turning point in the adoption of fibre sensing globally with delivery of security and leak detection from a single fibre system. This approach will enable us to demonstrate superior technical performance and value for money. With our partners ABB and Optilan we look forward to helping TANAP use the OptaSense technology to deliver the highest levels of pipeline availability and reduce the cost of asset ownership.”
Mr Bal Kler, Executive Director at Optilan said: “We are pleased to be partnering once again with the world’s leading fibre sensing company to deliver the world’s largest pipeline monitoring project. Implementation of this project for TANAP will deliver total security and monitoring over the entire pipeline length and follows on from other successful security projects in Turkey.”
OptaSense’s award-winning integrated DAS solution works across multiple functions via a single fibre-optic cable that effectively “listens” to the pipeline in order to provide detailed data about its current status. Any changes to the condition of the pipe are fed back through an interrogator unit in real time, allowing users to identify and address issues early and maintain the highest level of pipeline integrity and product throughput.
Leak and intrusion detection are vital to maintaining pipeline integrity and production maximisation in the oil and gas industry. In 2015 an attack on the Kirkuk-Ceyhan pipeline, which exports crude from Iraq to Turkey, halted operations resulting in significant repairs and thousands of barrels per day in lost deliverables.
*Control infrastructure includes telecommunication, pipeline monitoring, security systems, control systems and integrating SCADA (supervisory control and data acquisition)
The utilization of fiber optic technology is a relatively new technique however is considered a robust method for determining cluster efficiency for engineering purposes. Applications using fiber optic for seismic purposes have been limited, primarily due to directional detection and noise floor issues (e.g. Rassenfoss, 2014). This paper presents a methodology for comparing conventional, primarily mechanically driven, detection sondes to the use of fiber optic cable via seismically generated sources through vertical seismic profiling (VSP). Ultimately we will demonstrate the two comparative methods, through the utilization of a hydraulic stimulation detection project.
Devon Energy conducted a multi-well stimulation monitoring program residing in Lavaca County Texas with a target of the Eagle Ford Formation. Two horizontal wells were drilled 500’ apart laterally and 150’ differential in depth, Well B relative to Well A. The goal of the project was to determine if stimulation of the upper-landed well was detectable through fiber optic and conventional tool downhole geophysical and engineering methods. If detectability was determined feasible, a proxy of fracture description and stimulation would be useful for well placement aid in fracture models. In addition to the above an experimental Walk Above or Vertical Incident VSP (ZIVSP) was attempted inside of casing (e.g. Jones and Pereira, 2010).
Fiber optic recording is a relatively new technique, but has been considered a robust method for determining cluster efficiency. A few case scenarios have been identified utilizing the same cable for vertical seismic profiling, however require a need for an increased source effort. Here we show an example of applying the technique with minimal source effort and relatively high fidelity compared to conventional tools deployed in a nearby lateral. Additional to the downhole mechanically driven tools and fiber optic cable, surface microseismic, image log data and near-by petrophysical data were utilized for integration.
Click here to download the complete technical paper.
With the growing pressure to optimize data value and reduce costs, operators are continually seeking better ways to maximize value from exploration and production. One effective solution is to optimize the hydraulic fracture stimulation design of a shale gas well. However, a gap of understanding exists in how completion design relates to long-term reservoir production. Our motivation is to provide the data necessary to fill in the gaps and ultimately leverage unrealized production potential and cost savings.
The inability to effectively understand the dynamic and varying production behavior of a shale gas well lies within the sparse sampling of data. One method for wellbore production monitoring combines the use of a Production Logging Tool (PLT) and analysis. As a point sensor wireline tool, a PLT is not suitable for permanent, continuous measurement across a large producing zone. At best, a wellbore is logged at a few discrete points within its production life. To improve completion design, long-term observation of inflow production behavior is required.
The OptaSense permanent well monitoring solution provides long-term Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS). It features a permanent hardware system and portal service. Field data is processed with a flow/no flow algorithm to produce a real-time cluster efficiency metric. Field data and processed data are then streamed to the portal for online viewing and downloading. The portal and data are supported by OptaSense DxS Pro software, allowing users to download and perform in-depth analysis to generate quantitative results on demand. Through this setup, real-time and long term trends of individual stages and clusters can be observed. Observation of contributing cluster performance over a long period of time demonstrates whether cluster performance is influenced by completion design. The OptaSense permanent monitoring solution shows long-term behavior of a reservoir section, including regions of diminishing influence and changing cluster response, allowing for better reservoir management. The OptaSense permanent well monitoring solution also removes the requirement for multiple field acquisitions and provides continuous data.
With a long-term monitoring solution from OptaSense, you can develop smarter completion designs that optimize field development, from improving well, stage, and perforation spacing for maximized recovery to increasing operational efficiency that saves time and money.
For more information about our permanent well monitoring solutions, contact your local sales representative.
QinetiQ has appointed Jamie Pollard as CEO of OptaSense, the leading Distributed Acoustic Sensing (DAS) business and subsidiary of QinetiQ. Jamie brings over 20 years’ of experience leading and growing businesses within Schlumberger, the world’s largest oilfield services company.
Steve Wadey, CEO of QinetiQ said, “I am delighted to be making a positive investment in OptaSense by appointing Jamie Pollard as its CEO to augment the current leadership team and build on what they have already achieved. Jamie’s record of growing businesses at Schlumberger will prove invaluable as we look to take the business forward and realise its potential to change the way we monitor oil wells, transport networks and infrastructure.”
Jamie graduated with a degree in Mechanical Engineering from Loughborough University of Technology. At Schlumberger he ran and grew large global businesses and joint ventures, working across the UK, US, Continental Europe and Africa.
Jamie Pollard said, “I am really excited to be joining OptaSense, the undisputed market leader. DAS technology brings real business benefits across a range of sectors and I look forward to working with the excellent team in place at OptaSense to take it to the next level.”
Magnus McEwen-King, who built OptaSense from inception, will remain with the business as an Executive Director with a focus on strategic pursuits and industry partnerships.
Jamie Pollard brings a depth of oil and gas industry expertise that will be complemented by additional investment in an advisory board for OptaSense comprising senior specialists to provide further domain expertise in key target markets.
Mr Pollard will be joining the OptaSense leadership team at the annual Society of Petroleum Engineers – Distributed Fibre Optic Sensing Conference, which takes place 10-13 August in Napa, California, USA.
Traditionally, operators plan and execute a hydraulic fracturing project based in part on available seismic data, which lacks the resolution needed to see fine-scale geophysical features and reservoir extent. Without a detailed understanding of a reservoir’s geophysical characteristics, the chosen fracturing parameters may not be optimal, resulting in diminished performance and wasted money.
OptaSense has released an advanced method of imaging called microseismic interferometry that uses the microseismic events themselves as seismic sources to generate high-resolution three-dimensional images. Using data recorded on either DAS fiber optic tools or conventional three-component receivers, microseismic interferometry improves upon traditional microseismic processing which produces event locations (dots in a box) along with some event attributes but no image.
OptaSense’s new technique employs thousands of microseismic events to build up a 3D image of the stimulated reservoir volume and supply a high resolution image of the subsurface geology around event locations.
Microseismic interferometry works by gathering data from a long borehole seismic array, ideally with 3C sensors straddling the stimulation zone. The data is then processed in a conventional manner to produce event locations and magnitudes. Following this initial analysis, the full waveform data is processed using interferometry – imaging the P and S wave fields to produce a local image for each microseismic event. These local images are combined into one large 3D volume covering the entire extent of the frac zone. This analysis can be performed on newly-acquired microseismic data or on existing surveys.
The 3D interferometric image volume can be analyzed using standard seismic analysis tools and can be integrated with existing surface seismic interpretations, well logs, formation tops, horizons or geomechanical analyses to build a better understanding of the reservoir and its geology. This improved understanding may be particularly useful for planning additional wells in nearby areas or re-fracturing wells in the imaged area.
OptaSense’s microseismic interferometry method extracts high-resolution information from existing data. Customers benefit from optimizing the costs of completion and drilling as they can use the information to plan subsequent fracs in nearby areas, re-fracs in the same formation or for time-lapse reservoir characterization.
To read more, download the paper by clicking here.