Remote Pressure Monitoring that Put an Entire Drilling Campaign at Risk and how the Campaign was Saved
Authors: Ryba A. L. , Mahanti G. , Lawati S. , Kindi S. , Farsi W. 
Published: October 2023

A drilling campaign was planned in one of the siliciclastic Ghariff reservoirs in Southern Oman, a prolific field of fluvio-deltaic origin producing from multiple zones split into Upper, Middle and Lower Ghariff sands. These reservoirs are developed via an initial primary depletion phase followed by secondary recovery with use of peripheral water flood (Al Kalbani, Al Barwani, et al., 2023). Due to implementation of fracture injection in the field, safe drilling practices entail closing in water injectors (WI) nearest to wells being drilled. This is done to reduce the chance of encountering high pressures during drilling operations. The drilling campaign included three wells (Figure 1) in direct proximity to existing active injectors hence a clear requirement was defined to stop these injectors and allow sufficient time for pressure to dissipate before commencing drilling. The standard way of monitoring pressures in WI’s is through remote data connection to a Tubing Head Pressure (THP) transmitter (Figure 2). In the case described in this paper, the entire drilling campaign in the field was almost canceled due to a sustained high THP in one of the injectors directly offsetting the drilling site. This was in spite of the transmitter suggesting the drop in pressure to acceptable drilling limts.

Drilling Planning

As part pre drill preparation, a pore pressure prediction (PPP) is created for each well. Combined with fracture gradients for individual zones and resulting fracture pressure, the PPP defined drilling window and enables decisions on mud gradient to be used throughout drilling. While it would be possible to define such a range of PPP that reflects communication with active injectors such approach would be impractical and would result in significantly higher drilling costs. The cost of deferring injection for a few weeks and resulting temporary reduction in oil production is far lower than the extra cost of well design and conducting drilling operations in significant overpressure conditions. Instead of assuming the high pressures resulting from active injection it is therefore assured that injectors surrounding the drill site are taken offline (shut in) sufficiently earlier than drilling commences. Based on historical data, the minimum time off stream for all offset injectors to assure safe drilling was calculated and followed. Injectors supporting the target zone for the new wells are "Water Injector 1" to "Water Injector 3". Injectors supporting deeper zones (also taken off line, but not relevant to analysis from this paper) are named "Water Injector 4" to "Water Injector 7" (see Figure 1 for details).

The injectors adjacent to the drilling site within the same zone as the newly planned wells were mostly recent wells with some data gaps and data quality issues in flow meter readings. However, one three-week-long period of shut in that occurred in preceding months with data from the transmitter clearly showing that these three weeks were sufficient to drop THP to below 1000 kPa. This analysis, together with numerical (Sapphire) modelling done previously, formed the basis for THP-vs-time model used for assessing the duration of WI shut down period required. Data as used in the model (with data gap during shut in period due to no power, but clear trend before and after the shut down) is shown in Figure 3. Few shorter periods of shut in were also available, showing clear declining trend within the first hours offline, these trends were consistent with the conclusions drawn from Figure 3.