Fiber Optic Sensor Systems for Reservoir Fluids Management

Abstract

Abstract A reliable downhole sensor network will dramatically improve reservoir management practices and enable the construction of "intelligent" downhole well completion and control systems. Fiber optic technology will play a seminal role in the architecture of downhole imaging and control systems because of advantages of power, performance and reliability over conventional electronics. Results from a field test of a fiber optic seismic borehole receiver prototype demonstrate that a multi-level, fiber optic hydrophone system can improve the economics of Vertical Seismic Profiling (VSP) & cross-well surveys, and quicken the birth of permanent monitoring networks. Introduction In the current economic environment, it is particularly important to be able to maximize the monetary yield from a producing field. Although historical recovery rates in the US have been in the 30% - 40% range, an increase of 5% - 10% would mean billions of dollars to the industry, many more economic fields, and just as importantly, a technological stretch of oil reserves1. "Intelligent" well-completion systems are the latest effort to improve production efficiencies by better control of production in multi-lateral and multi-zone wells. Downhole sensor systems are required to monitor multiple production zones and to provide vital feedback for the control of remote tools and actuators. To date, about a third of the US Original Oil In Place (OOIP) has been produced with another 9 percent extractable by conventional or simple EOR methods2. As illustrated in Figure 1 from Fisher3, the remaining oil distribution consists of mobile oil in unswept zones (16%) and of immobile oil, which may be partially recoverable by Enhanced Oil Recovery (EOR) methods. Old field redevelopment targets this unswept mobile oil for reserve growth by infill wells, sidetracks or recompletions. New field development aims to avoid unswept mobile zones through optimum placement of wells and through active fluids management. In both cases, the reservoir engineer requires a detailed characterization of the reservoir with a spatial resolution that is unattainable using surface seismic imaging techniques. Downhole sensor systems are required to better image the reservoir structure, rock properties and fluids distribution4. 3-D VSP and cross-well imaging survey techniques, which use conventional receivers and a variety of surface and subsurface sources, currently allow us to achieve the required subsurface resolution. However, the economics of these tools generally restrict their usage to a limited set of assets. Because of consequential and logistical costs, many 3-D VSPs and cross-well surveys are economically marginal for the asset manager and/or the service company. Increasing the number of receiver levels is one solution to this cost issue. Unfortunately, without an accompanying increase in component and system reliability, these larger recording systems will not be viable. One example from the past is the introduction of digital marine streamer cables. Performance of the digital over analog streamers was an issue (the first commercial digital streamer had 12-bit resolution), but the greater reliability of the digital system over the old analog systems won the day for marine high channel-count streamers.