Category: Technical Papers

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.

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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.

 

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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.

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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.

 

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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.

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29 Oct 2014

Flow Monitoring and Production Profiling using DAS

Abstract

This paper discusses the application of DAS for flow monitoring. While previous publications (Van der Horst et al (2013, 2014)) focused on vertical and horizontal tight gas wells in North America, the focus here is on liquid producers and injectors in Brunei. Specifically, it was found that DAS has potential for zonal production and injection allocation across ICVs, monitoring interzonal inflow from the reservoir, monitoring artificial lift, tracking fluid transport through the well bore, detecting leaks, and monitoring wax build up or other types of deposition in the well.

Introduction

Distributed Acoustic Sensing is an emerging technology in the oil and gas industry, coming from the defence industry, which has the potential to revolutionize the way we secure our transport pipelines, acquire (micro-) seismic data, and monitor and optimize our wells and fields in the future. Following the successful introduction for pipeline integrity monitoring several years ago (Williams (2012)), Shell and OptaSense started a collaboration to develop DAS also for downhole applications (Koelman (2011), Koelman et al (2012, 2012)).  This has led to major developments in the area of in-well monitoring (Boone et al (2014), Johanessen et al (2012), Molenaar et al (2011, 2011), Ugueto et al (2014), Van der Horst et al (2013, 2014)) and geophysical imaging and surveillance (Mateeva et al (2012), Mestayer et al (2012), Webster et al (2013, 2014)). The focus of this paper will be on the application of DAS for in-well flow monitoring.

DAS offers many advantages over traditional surveillance methods such as production logging tools, gauges, or geophones. A standard telecom fiber can be used for time lapse or continuously for both in-well and seismic applications throughout the life of the well and can also be shared with other fiber-optic technologies such as Distributed Temperature Sensing (DTS).  The full length of a well can be interrogated simultaneously providing data at a spatial resolution as low as 1 m and at sample rates as high as 20 kHz. As a result DAS is a robust and potentially a cost-effective and powerful technology for permanent real-time monitoring of well operations. It also does not require well interventions, thereby reducing deferment and HSSE exposure.

The main drivers for pursuing fiber-optic technologies such as DAS and DTS are the increasingly complicated recovery mechanisms that we are going into, such as improved or enhanced oil recovery and unconventional oil or gas, the requirements to reduce the operational costs and HSSE exposure, and the need to increase production and reservoir recovery. In these types of environments there is a need for frequent and high-quality data that conventional logging methods often cannot offer. The reason is that they are either expensive, cause production deferment, increase HSSE risks, or because surveillance cannot be done frequent enough or over all depths of interest.  Especially offshore, subsea, or in horizontal wells the costs and complex logistics of traditional surveillance often cannot be overcome.

 

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19 Jan 2014

Fiber Optic Sensing For Improved Wellbore Production Surveillance

Abstract

Since our previous publication1 significant progress has been made to further mature the application of Fiber-Optic (FO) based Distributed Acoustic Sensing (DAS) for production and injection profiling. A considerable number of new field surveys were conducted to further improve the evaluation algorithms or workflows which convert the DAS noise recordings into flowrates from individual zones. For gas producing wells, a new graphical user-interface has been developed that allows the user to visualize and QC the data in real time. Additional flow and visualization software have been developed for single phase gas producers to enable the user to select and evaluate the data in a user-friendly manner using the most up-to-date evaluation algorithms.

There are still improvements to be made in enabling Distributed Sensing infrastructure, such as handling and evaluation of very large data volumes, seamless FO data transfer, the robustness & cost of the FO system installation, and the overall integration of FO surveillance into traditional workflows. It will take some time before all these issues are addressed but we believe that FO based applications will play a key role in future well and reservoir surveillance.

In this paper we present two recent examples of single-phase flow profiling using DAS. The first example is from a single-phase gas producer in one of the Unconventional plays in North America and the second example is from a long horizontal, smart polymer injector operated by Petroleum Development Oman (PDO).

Introduction

In oil and gas field development there is often a lack of high 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, waterflooded reservoirs, Thermal and Chemical Enhanced Oil Recovery (EOR) projects. One of the reasons that well surveillance data is not acquired in practice is that it often causes significant production deferment. Another reason is that often the data gathering surveys are expensive or create large operational risks associated when using conventional logging methods, particularly in high rate, highly deviated or long horizontal producer wells. In some cases, the small diameter production tubing limits access to the well with conventional logging tools.

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12 Jan 2014

Production : Fiber Optic Sensing for Improved Wellbore Production Surveillance

Oil Field Services

van der Horst, J., den Boer, H., in ‘t Panhuis, P,. Wyker, B., Kusters, R., Mustafina, D., Groen, L., Bulushi, N., Mjeni, R., Awan, K., Rajhi, S., Molenaar, M., Reynolds, A., Paleja, R., Randell, D., Bartlett, R., and Green, K., ‘Fiber Optic Sensing for Improved Wellbore Production Surveillance’, Paper 17528 presented at the IPTC, Doha, Qatar, Jan. 2014

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