When downhole tools that collect data were created, they stored the data in memory on the tool itself. The data were downloaded when the tool was next pulled from the hole. Communication with downhole tools while drilling is currently achieved with either mud-pulse telemetry or electromagnetic-based systems. The maximum data transmission rate (correlated with bandwidth) of these systems is about 10 bits per second. As a result, much of the information from measurement while drilling (MWD) and logging while drilling (LWD) must be processed and stored in computer memory associated with the downhole instrumentation near the drill bit.
Temperature-based production logging inversion for unconventional horizontal wells are highly sensitive to the accuracy of the temperature measurements. In order to get reliable results, the systematic bias of the measurements has to be smaller than 0.05 °F. DTS measurements suffer the error due to differential attenuation and instrument instability, which cannot be eliminated by averaging a long period of measurements and can potentially bias the production logging inversion. We developed a calibration workflow for double-ended DTS systems that reduces the systematic bias in the measurement. We attack the differential attenuation bias by comparing and averaging the measurements from the down-going and up-going fiber, avoiding or correcting locations where fibers are spliced or damaged. The offset bias due to instrument instability is calibrated using borehole gauge measurement and the DTS data itself. This calibration is performed in the frequency domain to improve the results. The calibrated results show significant improvement in the quality and accuracy of the DTS data. This work provides a detailed analysis and discussion on the error and bias in the DTS measurement. The public understanding of the limitation of the DTS system helps to push the service providers to improve their instrument design and calibration workflow. The calibration workflow presented here significantly improved the DTS data quality for several real cases.
Temperature logging has a long history for production and injection monitoring (e.g. Ramey Jr., 1962; Curtis and Witterholt, 1973). The recent development of the fiber-optic sensing technology, especially Distributed Temperature Sensing (DTS), makes borehole temperature measurements much more accessible and cost efficient. DTS measures absolute temperature along an optic fiber that can be several miles long, with a spatial resolution around 1 foot and temporal sampling interval between 1 second to several minutes. Many new applications have been developed using DTS in the oil industry, including hydraulic fracturing monitoring (e.g. Sierra et al., 2008; Holley et al., 2010), well integrity diagnostic (e.g. Gonzalez et al., 2012), production logging (e.g. Ouyang and Belanger, 2004; Jin et al., 2019), etc.
The generic term "intelligent well" is used to signify that some degree of direct monitoring and/or remote control equipment is installed within the well completion. The first computer-assisted operations optimized gas lifted production by remote control near the tree and assisted with pumping well monitoring and control. Permanent downhole pressure and temperature gauges are commonly run as part of the completion system and combined with data transmission infrastructure. With the development, successful implementation, and improving reliability of a variety of permanently installed sensors, it was perceived that the potential to exercise direct control of inflow to the wellbore would provide significant and increased economic benefit.
Intelligent wells are downhole flow control devices, sensors, power and communication systems, and associated completion equipment. This equipment is used to optimize production, improve recovery, and manage well integrity. Developing an intelligent-completion solution requires the clear definition of well and/or project objectives. Initially flow control devices were based on conventional wireline-operated sliding-sleeve. These valves were reconfigured to be operated by hydraulic, electrical, and/or electrohydraulic control systems to provide on/off and variable position choking.
Since the inception of the technology in the late 1990s, the use of intelligent well technology has focused on production acceleration, increased ultimate recovery, reduced operating expenditure (opex) and reduced project level capital expenditure (capex). The following examples illustrate applications in which this technology has been deployed. Using optimization, the strong lateral is restricted and more chance is giving for the weak one. This cannot be obtained without a downhole valve and surface control in addition to modeling. Objective Achieve production increase based on DTS analysis.
Remote well monitoring is the ability to provide data obtained in or near the wellbore without requiring access and entry for intervention to the well. Downhole permanent monitoring has been a widely accepted technology since the early 1990s. There are advantages and disadvantages to all monitoring systems; however, improvements in reliability and the realization of the added value of information have made this technology commonplace in offshore and some land applications. Remote monitoring can be coupled with remote flow control applications in intelligent wells, or it can be run as a standalone system. Sensor systems may be electronic or optical based.