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.
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.
This paper discusses installation of the longest high-performance (HP) and rotating 11-3/4" expandable liner on the Elgin field in the Central-North Sea sector of the UK that enabled isolating weak layers in the overburden formations on EIE well, providing sufficient mud weight window to permit drilling high pressure and gas bearing zones. The planning and execution of this record presented challenges beyond those encountered in standard well conditions due to narrow mud weight window (NMWW) and critical requirement of zonal isolation.
EIE well was the third of the 2015-2017 infill campaign on Elgin field. The well faced major challenges in the 12-1/2" section due to the NMWW which triggered the deployment of the contingent well architecture with HP 11-3/4" expandable liner. This critical requirement of zonal isolation significantly impacted the preparation and risk assessment of expandable liner operations. A new expansion assembly design was implemented to allow rotation of the 11-3/4" size system to improve the cement job quality. Moreover, all contingency procedures were significantly modified to ensure that the objective of the specific well constraints were considered.
After under-reaming while drilling 12-1/4" × 14" section down to planned depth, 860m of 11-3/4" liner was run with no open hole problems. This liner was successfully rotated at bottom prior to pumping cement and fully expanded without incident. The system was successfully pressure tested prior to drill-out of the plugs and the shoe assembly was drilled with no issues.
Running of an 860m HP 11-3/4" expandable liner and rotating shoe assembly on EIE well is a record (longest HP string run before was 360m) and considered as a remarkable achievement. However, liner objectives were not fully met and cement squeeze below the shoe had to be performed. Post-job investigation highlighted issues related to dart selection and related cement over-displacement, limited contingences in case of expansion pressure loss, and the ability to pull the liner to surface in a NMWW. These issues remain to be solved for optimisation of future deployments.
This paper provides information on the design and operational aspects that should be considered for expandable liner operations on complex wells with NMWW. Understanding advantages and limitations of the system will open up opportunities to improve the technology and help to reduce operational risk.
De Gennaro, S. (Shell U.K. Limited) | Taylor, B. (Shell U.K. Limited) | Bevaart, M. (Shell U.K. Limited) | van Bergen, P. (Shell U.K. Limited) | Harris, T. (Shell U.K. Limited) | Jones, D. (Shell U.K. Limited) | Hodzic, M. (Shell U.K. Limited) | Watson, J. (Shell U.K. Limited)
ABSTRACT: The Shearwater field located in the UK Central Graben represents one of the most challenging high-pressure, high-temperature (HP/HT) developments of its kind in the North Sea. During production, the strong depletion of the Fulmar reservoir caused a number of geomechanical-related problems, including the failure of the initial development wells, and consequently, loss of production. In order to reinstate production at Shearwater, five infill wells have been drilled and completed successfully. This success was largely attributed to a multidisciplinary effort to understand the post-production changes of the overburden. In this paper, a comprehensive 3D geomechanical model is presented that was used as a key design foundation for safe HP/HT well delivery. The model results and interpretations are discussed, and a summary of the current understanding of the evolution of the overburden from a geomechanical perspective is provided. The challenges associated with infill drilling and, in particular, the loss of fracture gradient and the closure of the drilling mud weight window between this and pore pressure, and how these have added complexity to the drilling practices are described. Finally, key technologies implemented to overcome these issues including Managed Pressure Drilling, Drill-In Liner and Wellbore Strengthening are discussed.
The Shearwater field located in the UK Central Graben represents one of the most challenging high-pressure, high-temperature (HP/HT) developments of its kind in the North Sea. At the time of the initial development, elevated pressures in excess of 15,000 psi and temperatures greater than 350°F, and structural geology complexity, posed major technical challenges to Shearwater. These challenges involved all aspects of well construction and production in HP/HT conditions. Despite the challenges, all initial development wells were drilled successfully.
During the first years of production, and similar to other HP fields, reservoir pressures dropped rapidly to 8,000 psi on average. The strong depletion of the reservoir, in combination with the high compressibility of the reservoir rock, resulted in compaction of the Fulmar sandstones and led to displacements, deformations and stress changes in the overburden rock. Compaction-induced stress changes in the overburden (“stress arching”) were the driving force for a number of geomechanical-related subsurface problems. During 2004-2007, it resulted in four production liners being sheared due to slippage along faults or bedding planes near the crest of the structure. Furthermore, over time, some initial development wells then experienced rapid A-annulus pressure increases, suggesting a leak of the production casing at Hod Chalk Formation level.
Davison, J. M. (Shell Global Solutions International B.V.) | Salehabadi, M. (Shell UK Exploration & Production) | De Gennaro, S. (Shell UK Exploration & Production) | Wilkinson, D. (Shell UK Exploration & Production) | Hogg, H. (Shell UK Exploration & Production) | Hunter, C. (Shell UK Exploration & Production) | Schutjens, P. (Shell Global Solutions International B.V.)
ABSTRACT: At the end of field life, wells require permanent plugging and abandonment (P&A) as part of decommissioning activities. Some UK fields developed in the 1970’s are reaching their end of field life, with UK industry estimates predicting well P&A costs over the next 30-40 years of 24 billion dollars. As well as the high financial cost, there is a significant HSSE exposure to ensure safe and reliable P&A such that no escape of hydrocarbons is possible to the near surface environment.
This paper discusses the role Geomechanics has to play in potentially reducing well P&A costs, but also ensuring integrity of the wells and formations over long time scales. Recent experience in the UK North Sea has highlighted the requirement for detailed geomechanical knowledge of the field. We will focus on three key areas for geomechanical analysis. Firstly, we discuss reservoir pressure re-charge and in-situ stress response, from simple pressure-depth plots to more complex 3-D numerical modelling of the stress changes in reservoirs and surrounding formations. An added level of complexity compared to ‘conventional’ geomechanical modelling is the ability to forward predict the reservoir pressure recharge over hundreds of years and the commensurate response of the in-situ stresses. Secondly, as well as the modelling of stress changes over time, Geomechanics has a key role to play in determining the opportunity of using shale creep deformation to create annular barriers in the place of cement. Lastly, in some cases the preferred P&A design for a well is not possible due to well access issues which then requires cross-flow analysis linked with the geomechanical response of permeable formations. This approach is required for containment risk assessment and application of ‘as low as reasonably practicable’ (ALARP) assessments for well and formation integrity. Each of these subjects will be covered with field examples from the UK North Sea which demonstrate the Geomechanical workflows employed and the impact these have had on the business.
This paper looks, rather uniquely, at an HPHT field in the UK Sector of the North Sea which was designed and developed during the mid 1990's and which, relatively recently, gave problems due to a gas leak from a well which was being worked on. The amount of gas emitted from the well caused full evacuation and the fact that the problem was solved with no injury gives full testimony to the high standard of the Operators Policies and Procedures. The well was killed from the top and a relief well was also drilled, designed to kill the well from the bottom. Unfortunately, the cost of a) loss of production and b) remedial works ran into £billions and the Operator was fined £1,125 million by the Law Courts for contravening the Health & Safety at work act. Sometimes, during the early design phases of a project company departments make decisions which turn out to be less than optimal simply because certain information wasn't known. This can be unfortunate and very costly. The field, Elgin, was named after a relatively nearby Scottish town. The field forms a part of the Central Graben and there were essentially two reservoir columns (the Jurassic overlying the Pentland). The paper tries to portray the excellence of planning, management and operations exhibited by the current world class / first rate Operator.
Graham, Robert (Shell U.K. Limited) | Geddes, Martin (Shell U.K. Limited) | Harris, Tim (Shell U.K. Limited) | Flaherty, Dominic (Shell U.K. Limited) | Shuttleworth, Nigel (Shell U.K. Limited) | McEwan, Bruce (Shell U.K. Limited) | Nordin, Noor (Shell U.K. Limited) | Cadd, Michael (Shell U.K. Limited) | O'Grady, John (Shell U.K. Limited) | French, Pete (Shell U.K. Limited) | Sandell, Richard (Blade Energy Partners) | Jeffries, Stuart (Blade Energy Partners)
The Shearwater field is a deep, high-pressure, high-temperature (HPHT) reservoir located in the UK Central Graben of the North Sea. The current drilling campaign represents the first round of well re-entries into the field following a campaign of slot recoveries to facilitate sidetrack development opportunities.
A high level of reservoir depletion (> 8000 psi) has resulted in significant changes to the drilling envelope that has added complexity to the drilling practices required to successfully exploit the remaining reserves.
Managed Pressure Drilling (MPD) Technology was pursued as an enabling technology to navigate within some very narrow margins in the first well of the redevelopment campaign. MPD was implemented in conjunction with drill-in liner and wellbore strengthening technologies to successfully deliver this first well and prove the techniques required to prolong field life.
To promote successful implementation of MPD in the target zone, the technology was employed in the previous hole section to gain experience with the equipment and procedures where pressure control was less critical.
MPD was used to control bottom hole pressure to manage background gas and facilitate changes to equivalent mud weight. It was further used to minimise the effects of loss/gain mechanisms and enable drilling through a tight margin between pore and fracture pressure while reducing the risk of borehole instability and losses. The technology was also used to determine appropriate mud weights for tripping and provide trip margin to avoid swabbing while tripping. In addition, MPD was used to facilitate cementing in tight margins.
This paper will highlight the multiple uses of MPD throughout the start-up of this current drilling campaign and key learnings enabling successful implementation of a new technology on the rig.
Van Bergen, Pim (Shell UK) | De Gennaro, Sergio (Shell UK) | Fairhurst, Fiona (Shell UK) | Hurry, Ravyn (Shell UK) | Concho, Maria (Shell UK) | Watson, James (Shell UK) | Sturgess, L (Shell UK) | Bevaart, Marc (Shell UK)
In preparation for a new phase of development of the deep, >8000 psi depleted, high-pressure, high-temperature (HPHT) Shearwater field in the UK Central Graben of the North Sea, the existing well stock had to be prepared to enable slot availability for sidetracking operations. Here techniques and key learnings gained from the slot preparation activities, in particular with respect to the chalk overburden, are described.
During the slot preparation activities new data on fracture gradients and the extent of porosity in the chalk was acquired. This information was then integrated with the results gained from the use of state of the art logging tools and unique data acquisition (including chalk hydrocarbon molecular and isotope compositions). In addition, an analysis of overburden time shifts from re-processed 4D seismic data was completed, along with geomechanical modelling work.
A new understanding was gained of the effects of reservoir depletion on the chalk, from being a solid uniform tight rock with very low permeability to a more heterogeneous permeable formation with differential reactions to reservoir depletion. The key learnings have been integrated into the ongoing slot recovery operations and future well plans. The overall integrated data allowed a greater understanding of the heterogeneity of the entire chalk section, which has been valuable in considering chalk overburden complexity.
Production Petrophysics plays a key role in reservoir surveillance and field management. This is particularly true for mature assets which present several challenges related to fluid contact movement, connectivity of reservoir layers and well productivity. Identification of infill targets therefore requires an integration of all sub-surface data. This paper presents examples from a mature North Sea field where cased-hole surveillance helped minimize risks in a high cost infill project. The Machar field, located in the UK Central North Sea is a fractured Cretaceous chalk and Palaeocene sandstone oil reservoir. The field development has been carried out in a phased manner due to a high degree of reservoir uncertainty, especially in the eastern flank. Enhancing the seismic sufficiently to fully assess prospects on the east became a priority, and ultimately led to drilling the east flank of the field in 2008.
Machar is a subsea field development and therefore petrophysical surveillance has been restricted due to limited well access and logistical challenges. During the infill drilling, it was therefore decided to use the opportunity and capture cased-hole saturation and production logs in existing wells. This data enabled the asset teams to understand fluid displacement mechanisms and upon integration with LWD and other logs provided the basis for the side track strategy. In particular,
location of the imbibition flood front, fracture conduits and differentiation between formation and injection water were critical in the delivery of a successful producer.
Two wells have been drilled on the eastern flank, one in 2008 and another in 2010. Baseline petrophysical surveillance was part of the data acquisition program in both wells. The initial objective was to use such data in Time Lapse mode with later surveillance. However, in-depth work identified immediate use when integrating with LWD and Wireline data.
The Machar field is located in UK block 23/26a in the central North Sea in 87m of water. It was discovered in 1976 and brought on stream in 1998. The reservoir is contained in a supra-diapir dome of Upper Cretaceous and Palaeocene strata that have been uplifted by the diapir and are sealed by Eocene mudstones. The field comprises two main reservoir units; the Upper Cretaceous and lowest Palaeocene chalks and Palaeocene turbidite sandstones. The Chalk Group is divided into the Hod, Tor and Ekofisk formations, the Tor being the dominant reservoir unit. The sands were deposited by NW-SE flowing turbidity currents that form many of the regional Palaeocene reservoirs.
The chalk reservoir has been the primary development target to date. Palaeocene turbidite sandstones account for ~25% of the STOIIP while the Chalk accounts for the remaining 75%. Communication around the field is normally good, with some key exceptions and there is evidence for pressure communication between the chalk and sand reservoirs.
The reservoir is currently under development using a voidage replacement water flood. However a ‘blow-down' phase is planned in the future, when water injection will cease, to allow solution gas drive and gas cap advance to increase oil recovery.
The structure has a vertical oil column of approximately 1300m TVDSS (Figure 1). The reservoirs are near flat at the crest but steepen to 45-60° on the flanks. The field performance is strongly influenced by a concentric fault geometry, evident in seismic data and drilled wells. Development wells cut numerous intensely fractured zones that aid well productivity and drainage in the low-permeability chalk matrix.
Recent reprocessing and reinterpretation of the seismic data has allowed mapping of the reservoir concentrically around the full extent of the diapir. The new interpretation resulted in an east-flank with significantly higher reservoir volumes and areal extent, allowing a well of sufficient length for an effective chalk producer, with considerable exposure to a highly fractured chalk reservoir, to be drilled.