Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
Challenging conditions in a HP/HT well in the UK Central North Sea, led to the deployment of a contingent expandable liner. Under-reaming tools were needed to facilitate running of the contingent liner. Under-reaming operations are associated with a degree of uncertainty on the final hole diameter. A technology was deployed to monitor cutter position, wear and vibrations. With the aim of removing the above uncertainty. An open-hole calliper run was performed to validate the technology.
The monitoring system utilizes an arrangement of sensors to measure variables that are critical to under-reaming operations. The sensors are housed within the expandable cutting structure of the under-reamer and comprises of a cutter block position indicator and a PDC cutting structure wear sensor. The monitoring system can also record downhole dynamics at the under-reamer. The system can therefore determine, via memory data, the actual under-reamer extension size at any point during the run, therefore allowing the minimum hole diameter to be derived. Providing immediate feedback at the rig site once the tool is at surface.
The first run globally of the 12 ¼" × 14" size is presented, the monitoring system recorded 187 hrs of data. The cutter blocks position sensor showed the cutting structure was fully expanded as required whilst pumping at drilling flow rate once the tool was activated. The wear sensors were fully active and showed no wear for the duration of the systems battery life. A combination of the positional and wear sensors indicated full gauge hole to the recorded depth. Due to the type of contingent liner the delivery of gauge hole was critical. As such, the data was validated using a dedicated open-hole calliper run on wireline. The calliper confirmed the open-hole diameter calculated based on data provided by the wear and position sensors. Based on this result the requirement for an open-hole calliper run can be reconsidered. In addition, the acceleration recorded was well correlated with the MWD recorded vibration data and allowed parameter recommendations to be generated.
The ability to monitor the position and status of the under-reamer cutting structure eliminates uncertainty on the final hole size following under-reaming operations and identifies any problem areas and their probable causes prior to running casing/liner. In turn this has the potential to eliminate the need for wireline runs and therefore reduce the open-hole time in a potentially unstable formation.
Salehabadi, Manoochehr (Shell UK Exploration & Production) | Susanto, Indriaty (Shell UK Exploration & Production) | Prin, Cindy (Shell UK Exploration & Production) | Freeman, Christopher (Shell UK Exploration & Production) | Laird, Rebecca (Shell UK Exploration & Production) | Gernnaro, Sergio De (Shell UK Exploration & Production) | Forsyth, Gatsbyd (Shell UK Exploration & Production) | Doornhof, Dirk (Nederlandse Aardolie Maatschappij B.V.)
Strong reservoir pressure depletion after years of production in a high pressure, high temperature (HP/HT) oil field in the UK Central North Sea led to reservoir compaction and stress changes in the overburden, which consequently had an impact on the fracture gradient profile. The understanding of the current fracture gradient is essential as it is one of the two key process safety inputs for further drilling or abandonment design. Besides ensuring hydrocarbons are kept within the reservoir/subsurface by assessing the caprock integrity, the ability to accurately estimate the fracture gradient range can potentially provide significant savings in the design and concept select phases, especially for HP/HT fields as most investments are very capital intensive. Stress changes in the overburden rock due to reservoir compaction ("stress arching effect") can be observed from the Time Lapse (4D) seismic data as a velocity slow down due to overburden stretching/ expansion. An integrated study was conducted by developing a 3D geomechanical model and coupling with 4D seismic data to assess the current fracture gradient in the overburden, specifically in the caprock. The results of this study show that overburden weakening is strongest at the top of the reservoir and extends up to mid overburden. The lateral extent of the weakening is confined by the area of the depleted reservoir. In this paper, we demonstrate the benefits of understanding the current fracture gradient, both for abandonment design by optimising the number of cement plug isolations and their location as well as for assessing the caprock integrity during long term abandonment.
Some of the first high-pressure/high-temperature (HP/HT) development wells from Elgin and Franklin have been exposed to sustained casing pressures in their "A" annulus, threatening the integrity of the wells. The sustained pressure in the annulus was attributed to ingress through the production casing of fluids from the overburden chalk formations of the Late Cretaceous. The mechanism triggering the ingress into the "A" annulus was uncertain until access to the production casing was achieved. A recent campaign to abandon development wells of Elgin and Franklin that had sustained "A"-annulus pressure brings new evidence on the mechanism causing the ingress. Temperature surveys have been acquired in the production tubing to identify the fluid-entry points in the production casing. Multifinger calipers have been run in the production casing, revealing several shear-deformation features. These deformations are localized along various interfaces, and are attributed to the stress reorganization associated with the strong reservoir depletion. A detailed analysis of the surveys shows that fluid ingress is occurring at distorted casing connections, if located close to weak interfaces along which shear slip occurs. The shear deformation is suspected to cause a loss of the sealing capacity of the connection, leading to gas ingress into the "A" annulus. This conclusion emphasizes the need to consider any potential for localized shear deformations in designing casing for HP/HT wells.