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Summary A flexible optical fiber cable, either as a wireline or a disposable fiber deployed using a pumped fiber payout shuttle, in a horizontal well, can be used to measure distributed near-static or dynamic strain. These measurements can be used to monitor the hydraulic fracturing treatment of nearby wells. We present a theoretical framework for the understanding of the cable behavior and to compare the theory with field measurements. The theory predicts the conditions under which slippage occurs between the optical fiber cable and the wellbore, if coupling is provided by Coulomb friction. For near-static strain, as used in crosswell strain monitoring, the theory explains the broadening of the strain zone detected with a wireline cable or disposable fiber when slippage occurs. However, for a grease-covered disposable fiber, the theory underestimates the coupling where the grease provides a level of adhesion between the fiber and the wellbore. Understanding the fundamental theory explains measured data and enables confident data interpretation regardless of sensing cable configuration. For the dynamic strain, the theory confirms the generally good response observed using the flexible cables for microseismic monitoring due to the low amplitude of the dynamic strains involved. The low amplitude of the strains means that the strain gradients and inertial forces are also small, such that Coulomb friction is sufficient to provide the needed coupling. An interesting result of the theory is the existence of a resonance condition allowing for large amplitudes to be detected faithfully even if only Coulomb friction is present. This resonance does not depend on signal frequency but on the match between the intrinsic travel speed of a disturbance on the cable and the apparent phase velocity of the seismic signal in the well direction. Most importantly, the theory enables (i) a comparison of different cable types for the near-static and dynamic strain applications, and (ii) better data interpretation and associated decisions. Field examples are provided to show both when the theory is applicable and where the obtained coupling exceeds what is predicted by the theory. The novel aspect of the paper is the first presentation of a theoretical background for the understanding of the performance of flexible cables inside horizontal wells used as static or dynamic strain sensors for the monitoring of hydraulic fracturing jobs.

Subsea control systems utilize electric and/or optical communication channels within subsea optical distribution systems for redundant, duplex telemetry between topside facilities and subsea control systems. Downhole fiber optic sensing (DFOS) systems utilize the same subsea optical distribution systems for establishing transmission paths between the same topside facilities and downhole sensing fibers. To date, subsea fiber optic control and sensing systems have been operated on independent subsea optical distribution systems. This redundancy introduces complexity and cost into the overall subsea optical distribution system required for subsea developments. We describe the systems that combine fiber optic communications for subsea control systems and downhole fiber optic sensing systems into the same subsea optical distribution system. This enables simultaneous operation of communications between the topsides and subsea control module, and the topside interrogation of multiple downhole fiber optic sensors while preserving dry-tree equivalent sensing performance.

Recent deployments of subsea optical distribution systems and single-fiber optical feedthrough systems have enabled distributed acoustic sensing (DAS) of subsea wells to augment existing electric pressure and temperature sensing systems. Following recent developments of multi-fiber optical feedthrough systems enabling multiple downhole fibers, we describe the concepts for all-optical downhole sensing solutions that combine distributed acoustic and temperature sensing (DAS/DTS) with discrete fiber Bragg grating (FBG) sensing of pressure and temperature gauge arrays while minimizing impact on subsea optical distribution. Since DAS, DTS, and FBG sensing operates at different optical wavelengths, we combine them via a wavelength division multiplexer (WDM) so they are distributed via the the same subsea fiber topology. This subsea fiber topology involves two transmission fibers in the umbilicals and subsea distribution systems to a remote and passive optical multiplexer and circulator assembly deployed in the optical flying lead (OFL) or optical feedthrough system (OFS) of the subsea tree. This enables the down-going transmission fiber to be split into three sensing fibers which are coupled to three downhole fibers via a multi-fiber optical feedthrough system: one fiber for DAS and DTS sensing, and two fibers for FBG sensing of pressure and temperature gauge arrays. The circulators enable dry-tree equivalent pulse repetition rates, regardless of the tieback distance, and via another remote wavelength division multiplexer (WDM), recombine the backscatter light from multiple downhole fibers into the up-going transmission fiber. This pure backscattered light can be selectively amplified prior to entering the receiver arms of the DAS, DTS, and FBG interrogators. The dry-tree equivalent sensing performance implies that the variety of DAS, DTS and pressure and temperature algorithms developed for reservoir and well diagnostics can be equally applied straightforward to DAS, DTS, and FBG-based pressure and temperature data acquired from subsea wells.

A flexible optical fiber cable, either as a wireline or a disposable fiber deployed using a pumped fiber payout shuttle, in a horizontal well, can be used be measure distributed near-static or dynamic strain. These measurements can be used to monitor the hydraulic fracturing treatment of nearby wells. It is the objective of this paper to present a theoretical framework for the understanding of the cable behavior and to compare it to field measurements. The theory predicts the conditions under which slippage occurs between the optical fiber cable and the wellbore if coupling is provided by Coulomb friction. For near-static strain, as used in crosswell strain monitoring, the theory explains the broadening of the strain zone detected with a wireline cable. However, the theory underestimates the coupling provided by a grease-covered disposable fiber where a level of adhesion between the fiber and the wellbore provides better coupling than possible by Coulomb friction alone. Understanding the fundamental theory explains measured data and enables confident data interpretation regardless of sensing cable configuration. For the dynamic strain, the theory confirms the generally good response observed using the flexible cables for microseismic monitoring due to the low amplitude of the dynamic strains involved. The low amplitude of the strains means that the strain gradients and inertial forces are also small, such that Coulomb friction is sufficient to provide the needed coupling. An interesting result of the theory is the existence of a resonance condition allowing for large amplitudes to be detected faithfully even if only Coulomb friction is present. This resonance does not depend on signal frequency but on the match between the intrinsic travel speed of a disturbance on the cable and the apparent phase velocity of the seismic signal in the well direction. Most importantly, the theory enables i) a comparison of different cable types for the near-static and dynamic strain applications, and ii) better data interpretation and associated decisions. Field examples are provided to show both when the theory is applicable and where the obtained coupling exceeds what is predicted by the theory. The novel aspect of the paper is the first presentation of a theoretical background for the understanding of the performance of flexible cables inside horizontal wells used as static or dynamic strain sensors for the monitoring of hydraulic fracturing jobs.

We examine the effect of reputation and status on venture capital fund performance, introducing an empirical link between the social evaluations of VCs and financial return of their funds. We hypot...

Deepwater production increasingly relies on a few precious wells that are complex and expensive. Success is critically dependent on our ability to understand and manage these wells, particularly at the sandface. These wells are filled with expensive “jewelry” like sand control and production allocation systems that aim at maximizing production and minimizing risk. While this smart equipment can mitigate many anticipated dangers, it can easily fail when something unexpected happens. For example, repairing a sand control system that failed due to plugging can cost US $30–40 million, while the costs of lost production due to long-term well impairment can be even higher. Lower-than-expected production is often referred to as “well underperformance” (Wong et al., 2003) and can be caused by various impairments: a plugged sand screen, contaminated gravel sand, clogged perforations, damaged formation around the wellbore or larger-scale compartmentalization. While 4D seismic can address large-scale compartmentalization, it has insufficient resolution to address near-well issues. Scarce downhole data from pressure and temperature gauges also cannot unambiguously characterize the impairment. This limits mitigation opportunities and prevents us from finding more effective drawdown strategies for high-rate, high ultimate-recovery deepwater wells. We strongly believe that geophysical surveillance in boreholes has a big role to play in identifying sources of well impairment and optimizing production. Here we describe one possible avenue—real-time completion monitoring (RTCM)—that utilizes acoustic signals in the fluid column to monitor changes in permeability along the completion. In essence, this is a miniaturized 4D seismic survey in a well. We illustrate the capabilities of acoustic surveillance through a series of full-scale laboratory tests with realistic completion and discuss opportunities for deployment in deepwater wells.

Deepwater production is challenged by well underperformance issues that are hard to diagnose early on and expensive to deal with later. Problems are amplified by reliance on a few complex wells with sophisticated sand-control media. New downhole data are required for better understanding and prevention of production impairment. We introduce real-time completion monitoring (RTCM), a new nonintrusive surveillance method that uses acoustic signals sent via the fluid column to identify permeability impairment in sand-screened completions. The signals are carried by tube waves that move borehole fluid back and forth radially across the completion layers. Such tube waves are capable of instant testing of the presence or absence of fluid communication across the completion and are sensitive to changes occurring in sand screens, gravel sand, perforations, and possibly in the reservoir. The part of the completion that has different impairment from its neighbors will carry tube waves with modified signatures (velocity, attenuation) and will produce a reflection from the boundary where impairment changes. We conduct a laboratory experiment with a model of a completed horizontal borehole and focus on effects of sand-screen permeability on transmitted and reflected acoustic signatures. These new findings form the basis of an RTCM method that can be thought of as “miniaturized” 4D seismic and as a “permanent log” in an individual wellbore. We present experiments with a fiber-optic acoustic system that suggest a nonintrusive way to install downhole sensors on the pipe in realistic completions and thus implement real-time surveillance with RTCM.

Permanent installation of fiber-optic (FO) sensors, whether discrete or distributed, provides beneficial monitoring of a wide variety of parameters during every stage of a well's useful life—from drilling and completions, through the productive period, up to and including permanent abandonment—assuming that the sensors do not fail during installation or subsequent wellbore intervention operations. Long-term reliability is critical to obtain maximum benefit of FO based sensor installations and is crucial to increased adoption of this technology in the oil and gas industry. FO system reliability depends on several factors and requires diligent attention to numerous details, a responsibility shared by manufacturers, service companies, and oil and gas operating companies. Unexpected signal degradation of FO cables experienced in several instrumented wells required an engineered program approach to understand the failures and guide system improvement developments. Multiple-wavelength optical time domain reflectometer (OTDR) technology was used to diagnose symptoms of the fiber degradation. The importance and usefulness of OTDR technology was recognized, and a program to monitor fiber “health” with measurements recorded at regular intervals was developed to capture crucial historical records of the fiber/cable performance before system installation, during installation, and after installation. The historical progression of optical signal degradation proved to be invaluable in discerning root causes for this degradation. In the problematic FO cables, OTDR traces suggested various failure modes, including hydrogen darkening, fiber bending, and, in one well, a cable breach. An enabler to frequent OTDR data collection is the ability to remotely operate the FO interrogation units and OTDR equipment. Travel to remote well locations is costly in terms of travel expenses and personnel. It interferes with accomplishing other tasks and often requires the assistance or presence of field operations personnel for onsite access. The system requirements and components used to remotely operate the onsite FO electronic interrogators in the monitoring program are described in this paper. Based on the OTDR data, additional testing programs were initiated, new cables were designed and assembled, and quality assurance protocols were added. This paper describes the optical fiber “health” monitoring program, reviews case histories, emphasizes the importance of this diagnostic information, and summarizes developments to improve FO system reliability. Significantly improved reliability has been recognized in current installations and is expected to continue for future permanent installations based on the FO “health” program learnings.

Fiber optic sensing, and specifically Distributed Temperature Sensing (DTS), are powerful technologies extremely well suited for monitoring of geothermal wells and geothermal energy production facilities. This paper will discuss fiber optic technologies for high temperature sensing and monitoring applications in geothermal energy plants.

Distributed Fiber Optic Sensing is a powerful technology with wide spread use in applications from down-hole oil & gas wells to environmental monitoring of streams. This paper will highlight some of the various technologies and applications. Recent advances in multi wavelength Raman systems will also be discussed.

Summary We present results of Real-Time Completion Monitoring (RTCM) with acoustic waves on a full-scale model of a cased deepwater well with sand-screened completion. First, we describe the results of active surveillance with a controlled source. Using permanent fiber-optic sensors and observing changes in tube-wave signatures we detect changes in permeability along the completion. We prove that such measurements can be conducted while the well is flowing and show that continuous surveillance also allows monitoring technological processes such as gravel packing. Then we describe the first results of passive listening that allows locating flowing perforations and speculate on the possibility of detecting flow velocity. Finally, we outline a possible path to implement RTCM technology.

Distributed Temperature Sensing (DTS) systems have offered oil and gas companies critical asset monitoring solutions for years. DTS monitoring solutions provide real-time, dynamic temperature data with high accuracy, fine resolution and fast measurement speeds. DTS systems can provide tens of thousands of discrete temperature measurement readings along the complete length of an optical sensing fiber. These systems provide significant cost savings by identifying the location of leaks, optimizing gas lift operations, identifying under-performing zones, and monitoring thermal changes in steam drive applications. This paper discloses the first truly self-correcting DTS solution, which incorporates a revolutionary dual laser technology. This technology provides energy companies with the simplest, fastest, and most reliable DTS deployment available to the industry, combined with a capability to automatically correct for dynamic changes to the sensing fiber.

Fiber Optics is a key technology for Reservoir Monitoring but the uptake has been slow. This paper reviews some of the barriers and shows field deployments where the issues have been resolved.

Deepwater production is challenged by well underperformance problems that are hard to diagnose early on and expensive to deal with later. Problems are amplified by reliance on few complex wells with sophisticated sand control media. New downhole data is required for better understanding and prevention of completion and formation damage. We introduce Real-Time Completion Monitoring (RTCM), a new non-intrusive surveillance method for identifying impairment in sand-screened completions that utilizes acoustic signals sent via the fluid column. These signals are carried by tube waves that move borehole fluid back and forth radially across the completion layers. Such tube waves are capable of "instant" testing of the presence or absence of fluid communication across the completion and are sensitive to changes occurring in sand screens, gravel sand, perforations, and possibly reservoir. The part of the completion that has different impairment from its neighbors will carry tube waves with modified signatures (velocity, attenuation) and also would produce a reflection from the boundary where impairment changes. The method relies on permanent acoustic sensors performing acoustic soundings at the start of production and then repeating these measurements during the life of the well. Thus, it could be thought of as "miniaturized" 4D seismic and "permanent log" in an individual wellbore. In the meantime repeated conventional wireline measurements can be performed to assess the completion permeability.