Using Fibre-Optic Distributed Temperature Measurements to Provide Real-Time Reservoir Surveillance Data on Wytch Farm Field Horizontal Extended-Reach Wells

Brown, George; Kennedy, B. W.; Meling, Trond Stokka

doi:10.2118/62952-ms

Cited by 51 publications

(12 citation statements)

References 2 publications

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“…It is not the purpose of this paper to describe how DTS temperature measurements are obtained, this has been described in many previous papers 8,9 . However, it is worth pointing out that the system can obtain a temperature curve sampled every meter along the entire length of the slickline in time intervals as small as one minute.…”

Section: Slickline Fiber Systemmentioning

confidence: 99%

Monitoring Inflow Distribution in Multi-zone, Velocity String Gas Wells Using Slickline Deployed Fiber Optic Distributed Temperature Measurements

Huebsch¹,

Moss²,

Trilsbeck³

et al. 2008

All Days

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Fiber-optic systems are able to generate a temperature log along an optical fiber using a laser source and analysis of the backscattered light. This paper details a novel application of this technology using an optic fiber embedded in a 1/8 th inch slickline cable to calculate the inflow distribution of multi-zone gas wells with velocity strings.EnCana's multi-zone gas wells in the Deep Basin of Western Canada are often completed with production tubing landed near the lowest perforated interval to act as a velocity string and lift produced water to surface. This completion technique makes spinner production logs impossible to run without initially performing a wellsite operation to lift the tubing shoe above the reservoir, requiring either a workover rig or a snubbing unit. Running a slickline containing an optical fiber to the bottom of the tubing and producing the well up the annulus for a short period allows the temperature profile of the well to be measured and therefore, the inflow distribution of the well can be calculated.Determining the inflow distribution of multi-zone gas wells now becomes a simple slickline operation with no tubing shift required. Additional benefits are the detection of crossflow on shut-in and the measurement of flowing bottomhole pressure when a gauge is run at the end of the slickline. The process is cost effective, less risky than conventional production logging, and the slickline can be safely employed where there is significant surface pressure.The paper uses case studies validated by spinner log comparisons to demonstrate that slickline fiber optic distributed temperature sensor measurements are a viable method for performing reservoir surveillance in multi-zone gas wells with velocity strings in Western Canada. Utilizing fiber optic measurements in these wells reduces operating costs and should ultimately lead to increased efficiency of reservoir stimulation practices.

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Section: Slickline Fiber Systemmentioning

confidence: 99%

Monitoring Inflow Distribution in Multi-zone, Velocity String Gas Wells Using Slickline Deployed Fiber Optic Distributed Temperature Measurements

Huebsch¹,

Moss²,

Trilsbeck³

et al. 2008

All Days

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“…diameter control line in a U-tube configuration was installed in BP' s Wytch Farm Well M-17 attached to the production tubing and run across the reservoir interval attached to a stinger hung below the tubing. 9 The optical fiber then was pumped in place after running the completion. Temperature measurements have been recorded since the well was put on production in 1999.…”

Section: Case Studiesmentioning

confidence: 99%

Optical Fiber Sensors in Upstream Oil & Gas

Brown

Hartog

2002

Journal of Petroleum Technology

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Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Optical fibers have, in the past few years, begun to gain acceptance as permanently installed downhole sensors, although trials were carried out as long ago as 1990.1 Optical-fiber sensors are fully passive, totally immune to electromagnetic radiation, and small enough that, in certain cases, they can be installed deep in a well after the completion itself has been run. The strong E&P industry interest in optical sensors derives mainly from the expectation of a higher reliability than conventional gauges because of the absence of active electronics in the downhole device. The technology that these devices exploit was developed mainly for the telecommunications industry during the past 35 years.2 The optical attenuation of the best fibers is well below 0.2 dB/km (equivalent to a signal reduction by a factor of 10 for every 50-km of propagation path), and a usable information transmission rate is well in excess of 1 Tbit/s baud rate. Thus, optical fibers are a well-developed, high-bandwidth, low-loss transmission medium. The telecommunications industry has standardized on a fiber diameter of125 µm that is sufficiently small to be flexible, yet retaining reasonable strength. A conventional optical fiber consists of a central core (typical diameter of5 to 50 µm) surrounded by a cladding of slightly lower refractive index. In general, both regions are made from silica, modified by the addition of materials to tailor the refractive index profile and the dispersion of the structure thus formed. A coating is applied to the fiber (typically to an outer diameter of 250 µm) to protect the surface from scratches, which will weaken the fiber, and to buffer it from microbending that would cause light to be lost. For oilfield use, higher levels of fiber protection for temperature, chemical attack, and mechanical abrasion and crushing are required. In increasing order of effectiveness, coatings have been manufactured from ultraviolet curable acrylates, silicone rubber, fluorated polymers, polyimides, and metal. In general, a metallic tube, similar to a 1/4-in. diameter controlline, further protects the coated fiber. Commercially available sensors can be categorized into those that aim to replace conventional permanently installed devices (such as pressure gauges and flow meters) and replaceable, distributed measurements [such as a distributed temperature system (DTS)]. Pressure Sensors There are several ways in which an optical fiber can be turned into a pressure sensor. Two methods currently in use are fiber Bragg gratings (FBG)and Fabry-Perot interferometry. An FBG3 is a device consisting of a short piece of fiber, which has a periodic modulation of the refractive index longitudinally along the fiber axis. Primarily, FBGs are narrow-band reflectors that transmit all wavelengths with little loss, except for a narrow range centered on a wavelength that matches the pitch of the index modulation. Reflection bandwidths as low as 1 GHz can be manufactured, and FBGs are used as filtering devices in the telecom industry. More sophisticated FBGs are used as band-pass filters or as dispersion-compensating devices. For sensor applications, FBGs work by stretching the fiber in which the grating is inscribed, thus altering the wavelength of the reflected light. The Fabry-Perot technique4 uses the interference pattern setup by the reflection of laser light from two reflectors, such as the cleaved ends of fibers placed in close proximity (approximately 50 µm) and sealed together in a 350-µm diameter silica tube. The gap between the mirrored fiber ends varies mechanically by fluid pressure acting externally on the tube causing the interference pattern set up between the mirrored ends of the fiber to change with the imposed external pressure. Unfortunately, neither of these systems yet provides the pressure resolution and accuracy available in the current generation of quartz electrical gauges, as shown in Table 1. Neither has their reliability yet proved superior, although only a few gauges have been installed and it is probably too early to make a direct comparison with electrical equivalents. Installation requires that the gauge be in a mandrel, allowing transmission of reservoir pressure to the sensor through a bellows. The mandrel is installed on the production tubing in a fashion similar to electrical-pressure-gauge mandrels. Thus, the whole downhole instrumentation must be installed with the completion.

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“…Amongst others, DTS has been shown to enable detection of flow behind casing, cross-flow during shut-in or production, water breakthrough (Brown et al 2000), to enable the evaluation of production along multilaterals (Clancy et al 2002), or monitor fluid placement during injection Sierra et al 2008). Villesca et al (2011) summarize the four main methods used for the analysis of DTS temperature survey for injection profiling.…”

Section: Introductionmentioning

confidence: 99%

Using Fiber-Optic-Enabled Coiled Tubing to Quantify Fluid Placement and Optimize Stimulation Effectiveness During Matrix Stimulation Treatments in Carbonate Reservoirs

Ramondenc

Baez

2013

All Days

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When performing matrix stimulation treatments, coiled tubing (CT) is a preferred placement technique due to the ability to spot fluid in front of the target zone(s). This method becomes a key solution when formation heterogeneities require a very selective fluid placement strategy.In today's industry, the most common approach is to design a treatment with volumes of stimulation and diverter fluids that are determined largely based on local practices. Often, it amounts to targeting a uniform stimulation, thus requiring a predefined amount of treatment fluid per length of total pay zone. That approach, although widely used and accepted, may not necessarily yield an optimum stimulation.We present an alternative technique that relies on the accurate quantification of fluid placement along the formation in order to define the respective volumes of stimulation and diverter fluids to be pumped. This method relies on the analysis of the distributed temperature sensing (DTS) data recorded by a fiber-optic line enclosed inside the CT and data processing through a fast interpretation algorithm to yield a zonal coverage profile. During a job, DTS data corresponding to the preflush can be used to estimate the initial placement distribution across the pay zone. This allows stimulation engineers to determine the best strategy for the subsequent well stimulation treatment, including fluid volumes and placement sequence. After every major pumping stage, a new DTS analysis assesses how the formation reacted to the treatment, improving placement strategy.This method has been used in multiple matrix stimulation treatments of injector and producer wells. The described innovative approach allows engineers to make more informed decisions between stages, optimizing fluid resources, fluid placement and, ultimately, stimulation effectiveness. It also leads to noteworthy advantages when designing new acidizing treatments, as companies can build on previous experience from similar wells and fields.

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Using Fibre-Optic Distributed Temperature Measurements to Provide Real-Time Reservoir Surveillance Data on Wytch Farm Field Horizontal Extended-Reach Wells

Cited by 51 publications

References 2 publications

Monitoring Inflow Distribution in Multi-zone, Velocity String Gas Wells Using Slickline Deployed Fiber Optic Distributed Temperature Measurements

Monitoring Inflow Distribution in Multi-zone, Velocity String Gas Wells Using Slickline Deployed Fiber Optic Distributed Temperature Measurements

Optical Fiber Sensors in Upstream Oil & Gas

Using Fiber-Optic-Enabled Coiled Tubing to Quantify Fluid Placement and Optimize Stimulation Effectiveness During Matrix Stimulation Treatments in Carbonate Reservoirs

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