Distributed Acoustic Sensing is a novel technology for seismic data acquisition, particularly suitable for Vertical Seismic Profiling. It is a break‐through for low‐cost, on‐demand, seismic monitoring of reservoirs, both onshore and offshore. In this article we explain how Distributed Acoustic Sensing works and demonstrate its usability for typical Vertical Seismic Profiling applications such as checkshots, imaging, and time‐lapse monitoring. We show numerous data examples, and discuss Distributed Acoustic Sensing as an enabler of seismic monitoring with 3D Vertical Seismic Profiling.

3D VSP has long been viewed as conceptually attractive for illuminating targets under complex overburden, both for exploration purposes and for time-lapse monitoring of reservoirs. However, the widespread use of 3D VSP has been hindered by the cost and risk of deploying geophones in a borehole, and by the limited availability of accessible wells. These hurdles are largely removed when acquiring downhole seismic with a new measurement called distributed acoustic sensing (DAS).

3D VSP has long been viewed as conceptually attractive for illuminating targets under complex overburden. However, the widespread use of 3D VSP has been hindered by the cost and risk of deploying geophones in a borehole, and by the limited availability of accessible wells. These hurdles are largely removed when acquiring downhole seismic with Distributed Acoustic Sensing (DAS) instead of geophones.

Downhole seismic monitoring has become an alternative to more conventional surface seismic in cases where the latter has low signal-to-noise ratio or poor repeatability, or when frequent monitoring of a local target is required. Downhole 3D VSP monitoring has been applied to both onshore (O'Brien et al., 2004; Kiyashchenko et al., 2011) and offshore environments (Wu et al., 2011). In onshore environments, surface seismic repeatability often suffers from surface noise and near-surface variations caused by water-table changes or surface facilities construction. For VSP surveys, the wavefield separation into downgoing and upgoing fields presents an opportunity to discriminate between near-surface and reservoir changes, thus making time-lapse applications more effective.

Petroleum Development Oman (PDO) is currently redeveloping a thick deep heavy oil reservoir using steam flooding. Steam has been injected in the first inverted 7-spot pattern (1P) since late 2008. An areal surveillance plan was created together with Shell International EP (SIEP) to test different monitoring techniques in order to select the most cost-efficient one for full field deployment. Ideally, the selected method would improve understanding of the thermal recovery concept and optimise further pattern development. The plan included three crosswell seismic profiles, 3DVSP and surface seismic, all in time-lapse mode. The 2006 surface seismic was used as the baseline for the surface seismic acquired in 2012. The data shows very good repeatability. However as the project construction phase took place after 2006, the 4D surface seismic was influenced by the 4D noise caused by surface changes. Detecting 4D signals is challenging particularly with the relatively small amount of injected steam. In contrast, crosswell seismic data and the 3DVSP were acquired after the construction work took place. The crosswell seismic 4D velocity profiles showed changes below and above top of reservoir, which led to the consideration of geomechanical effects. The 3DVSP data indicated reservoir changes towards the north of the injector which is in line with the temperature surveys, also indicating preferential changes towards the north. These encouraging results led to a second monitor 3DVSP acquisition followed by a pilot 3DVSP using a fibre-optic cable installed in the well for distributed acoustic sensing (DAS). The second monitor 3DVSP shows that previous 4D signals have moved further towards the north. It also indicates additional changes at the bottom perforation zone (as injection was shifted to bottom) with a preferential movement towards the north as well. Furthermore DAS VSP was found comparable enough with the conventional VSP and therefore it can detect reservoir changes. A plan is being worked to fit the existing observation wells with DAS cables and acquire a major 3DVSP baseline. The DAS cable will be combined with distributed temperature sensing (DTS) to maximize the value of the installation plan.