Category: Oil & Gas

19 Oct 2016

OptaSense Collaborates with Leading Research Institution to Install Fiber Optic Seismic Array

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.

03 Aug 2016

Technical Comparison of Downhole Methods through Fiber Optic VSP, in the Eagle Ford Formation

Summary

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.

Introduction

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.

13 Jul 2016

Permanent Well Monitoring Solutions for Optimal Fracture Design

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.

27 Mar 2016

Microseismic Interferometry: Transforming dots in a box into a 3D seismic image

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.

28 Sep 2015

Velocity Tracking for Flow Monitoring and Production Profiling Using Distributed Acoustic Sensing

In this paper, we will share the recent work that was done to understand how bulk flow rates and fluid composition may be derived in single-phase and multi-phase flow by tracking the slopes (velocities) of coherent features detected using Distributed Acoustic Sensing (DAS). Both laboratory experiments and real field examples will be presented to demonstrate how velocity features can be detected and attributed to events such as slug flow or sound waves. Speed of Sound (SoS) analysis can in principle be used for determining changes in the fluid composition in multiphase flows, which provides opportunities to detect fluid interfaces and water or gas breakthrough. On the other hand, slowly moving features such as slugs or turbulent eddies can be used to derive bulk flow velocities, which may be used for injection or production profiling. The evaluation method directly derives velocities by Fourier transforming the raw DAS data in the temporal and spatial domains without applying any calibration steps. It can therefore be used to monitor flow in wells on a drive-by or continuous basis without a need for reference flow data.

 

Click here to download the complete technical paper.

22 Jul 2015

Estimating Stimulation-Zone Anisotropy Effects During Microseismic Monitoring

Summary

Hydraulic fracture operations can be optimized using knowledge about the stress regime, flow permeability, and fracture networks in the subsurface. Surface seismic data and nearby well data give a first assessment of the properties present in the hydraulic fracture treatment zone, though on vastly different scales and at different resolutions. When hydraulic stimulation operations are monitored using downhole seismic sensors, microseismic events can be used to derive valuable velocity anisotropy estimates in-situ throughout the entire fracturing operation. These estimates can be both time and space variant. We show a real data example where microseismic events were recorded using a 40 level array of 3-component downhole seismic sensors in an observation well straddling the treatment zone in depth. The observed microseismic event gathers exhibit shear wave splitting even at the onset of treatment operations due to anisotropy which was not readily predicted by either surface seismic or sonic scanner logs. We demonstrate that this apparent contradiction can be explained by proper upscaling of sonic scanner data using equivalent medium theory. Using a group-theoretical approach, we calculate an anisotropic replacement medium that explains the measurements from surface seismic, VSP and microseismic data while also preserving the well-log defined properties. Although the fine-scale log velocities are isotropic, this averaging shows that some layers exhibit anisotropic behavior at larger seismic scales. We extract anisotropy parameters epsilon, delta, and gamma (Thomsen parameters) from the upscaled layers. These anisotropy estimates explain the shear-wave splitting observed in the data. Estimating anisotropy parameters in the fracture zone both before and during the treatment opens up the possibility of time-lapse characterization of the fracture zone anisotropy on a stage-by-stage basis. Reconciliation of microseismic observations, surface and sonic scanner data through upscaling using an equivalent medium approach bridges the resolution gap and allows further detailed frac zone analysis.

Click here to download the complete technical paper.

13 Jul 2015

Monitoring Hydraulic Fracturing Operations Using Fiber-Optic Distributed Acoustic Sensing

Abstract

Taking downhole measurements during a hydraulic fracturing operation has many challenges, mainly the instrument survivability inside the hostile, high pressure, abrasive environment inside the casing during injection. Therefore, instrumentation must be attached on the outside of the casing, which has its own challenges in running-in-hole, cementing, pressure, etc. A fiber-optic cable with protective jackets can be permanently installed on the outside of the production casing and used to measure acoustics and temperature across the entire length of the borehole, without well intervention, for all operations from completions to production to abandonment. Fiber-optic distributed acoustic sensing (DAS) systems work by pulsing light into a fiber and measuring the backscattered light along the fiber length. An acoustic pressure wave that contacts the cable will create a small strain in the fiber and change the backscatter profile. The strain can be measured at surface, depth-matched using the speed of light in the fiber, and converted back into an acoustic signal. This paper will describe some of the acoustic events and signatures related to a typical plug-and-perf hydraulic fracturing operation including: wireline gun tracking, perforating, bridge plug setting, ball drops, and injection (axial flow and flow through perforations). Although this paper will only describe a typical signature of the listed activities, it will be evident that such continuous full wellbore measurements can be useful in redesigning and optimizing future operations, troubleshooting well problems, and making real-time operational decisions to avoid or mitigate non-productive time.

 

Click here to download the complete technical paper.

28 Apr 2015

OptaSense and Weatherford partner to deliver integrated well surveillance solutions

Farnborough, 28 April, 2015: OptaSense, a QinetiQ company, and Weatherford International plc have partnered in a strategic alliance to deliver integrated optical sensing solutions designed to optimize well planning, construction and production across the asset lifecycle.

The partnership combines OmniWell™ in-well optical production and reservoir monitoring systems from Weatherford with optical Distributed Acoustic Sensing (DAS) technology from OptaSense, including DAS-VSP™ vertical seismic profiling (VSP), DAS-HFP™ hydraulic fracture monitoring and DAS-Flow™ production flow monitoring.  These capabilities will provide customers with robust and actionable information that improves reservoir management and ultimate recovery.

Weatherford’s sensing technology includes pressure and temperature gauges, distributed temperature sensing, array temperature sensing, flow measurement, and seismic sensors.

Magnus McEwen-King, Managing Director of OptaSense, said “When Weatherford sensing technology is combined with DAS technology from OptaSense, the solution will deliver enhanced data acquisition and monitoring of seismic activity, well construction, completion and fracture operations, and production flow. In addition to acquiring accurate data in real time, OptaSense DAS technology can also reduce data acquisition costs by eliminating the need for well intervention.”

OptaSense’s innovative DAS technology offering complements Weatherford’s proven high reliability in-well technology. Together, these technologies provide a more complete, integrated, well surveillance solution. It will include multi-point and distributed VSP acquisition, production flow monitoring and hydraulic fracture monitoring, enhanced with microseismic imaging—which are critical in optimizing well performance.  The solution will also add value to customers with existing optical systems who are interested in DAS acoustic monitoring.

Weatherford and OptaSense have established a leading position in providing optical reservoir monitoring systems around the globe, installing and/or monitoring optical sensing solutions for more than 1,000 wells.

Both companies will continue to offer their respective products and services independently but together they will bring forward an integrated solution that delivers long term value to the customer.

03 Mar 2015

Cloud-Based Solution for Permanent Fiber-Optic DAS Flow Monitoring

In 2014, a first permanent installation of a fibre-optic (FO) distributed acoustic sensing (DAS) system was piloted in a tight gas well in Northern British Columbia. The project had three goals; to permanently monitor flow rates along the entire well bore, to make that information available to collaborative teams worldwide in real-time and to advance the system for future installations.

In oil and gas field development there is often a lack of frequent quality well and reservoir surveillance (WRS) data for quality decision making; leaving significant reservoir or well performance uncertainties potentially leading to suboptimal reservoir development. The need for frequent and good quality surveillance data is highest in complex reservoir developments such as unconventional plays, water-flooded reservoirs, thermal and chemical Enhanced Oil Recovery projects.

Often, well surveillance data is not acquired in practice because of concerns associated with production deferment, costs & logistics, HSE exposure or because it creates operational risks associated with well interventions when using conventional logging methods.

The attractiveness of FO-based surveillance lies with the fact that once the passive FO cable has been installed, no subsequent well interventions are required to collect downhole data; allowing for continuous (long-term) measurements or repeated measurements as and when required while eliminating the concerns associated with conventional logging methods.

The pilot system deployed at the well site is continuously measuring and recording qualitative and quantitative flow information. Using a secure web browser, the asset team can access the real-time and historical data when required or share with collaborative teams worldwide. The pilot has helped identify where improvements can be made in the enabling Distributed Sensing infrastructure such as handling and evaluation of the large data volumes, seamless data transfer, the robustness of the system installation and the overall integration of data into the full workflows. It will take further development of the system to implement all these improvements, but it is clear that FO based applications will play a key role in future well and reservoir surveillance.

This paper presents the system architecture and details the lessons learnt in designing, commissioning and running this system including the extraction of low data rate, actionable, qualitative data from distributed fibre-optic sensors and the IT challenges of creating a reliable, permanently installed system.

Click here to download the complete technical paper.

19 Feb 2015

Fourth generation OptaSense Distributed Acoustic Sensing system provides the highest data quality for borehole imaging

Farnborough, 19 February 2015: OptaSense, a QinetiQ company and global leader in Distributed Acoustic Sensing (DAS), has successfully demonstrated improved sensitivity of its DAS Interrogator Unit (IU).

As part of its ongoing product development, a pre-production version of the 4th generation of the OptaSense DAS IU was used to acquire a Vertical Seismic Profile (VSP) on a Carbon Capture and Sequestration (CCS) well during customer trials this month in North America. In these tests the new 4th generation IU achieved the targeted 6dB increase, a four times increase in sensitivity over the previous 3rd generation system.

The next generation ODH4 Interrogator Unit will also have a wider receive bandwidth, finer spatial resolution and greater programmable flexibility so it can be operated simultaneously in one or more acquisition modes. These features will be implemented in the commercial release of the 4th generation IU due in Summer 2015.

Magnus McEwen-King, Managing Director of OptaSense said, “The development of this 4th generation system once again pushes the boundaries of known performance. Our DAS-VSP™ service is already reducing the cost of data acquisition. Our 5th generation system, which is in development with Shell, is also showing great gains that will see OptaSense DAS capability deliver on an extremely ambitious technical target.”

The 4th generation IU will acquire higher quality DAS-VSP™ measurements, enabling geophysicists to see clearer images of the subsurface with the unique flexibility afforded by acquiring seismic measurement on an optical fibre deployed downhole.

The 4th generation IU is also expected to improve microseismic monitoring with smaller events now detectable, and flow monitoring where the simultaneous use of more than one acquisition mode will extend the ability of DAS to accurately measure inflow and axial flow rates across the length of the well.