A suite of subsea intervention case histories at the Bacchus oil field in the North Sea will demonstrate how one operator matured intervention planning to address well entry challenges using learnings gained over the course of successive jobs. This contributed to better management and mitigation of potential risks leading to slickline performance improvement for gas lift valve reconfiguration, the successful deployment of coiled tubing to clean out asphaltene deposits in a live subsea oil well from a monohull vessel and setting of a retrofit gas lift straddle to optimize and secure production. The paper outlines intervention asset selection, work programme development and risk mitigation measures related to subsea tree valve function issues and loss of full bore access caused by asphaltene and wax deposits. Light well intervention vessel and mobile rig operations using deployment methods including slickline, digital slickline, electric line and coiled tubing are described. The role of production technology work undertaken to better understand the nature of organic deposits in the wells and how that contributed to anticipating well access risks and inform intervention planning will be highlighted. These real field examples add to the knowledge base of well services and production technology challenges faced during subsea well intervention and highlights approaches to overcome them.
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.
Yanez, Marianne (Schlumberger) | Tyagi, Chirag (Schlumberger) | Steiger-Jarvis, Merigon (Schlumberger) | Bailey, James (Schlumberger) | Shadrina, Maria (Schlumberger) | Dingwall, Scott (Ithaca Energy)
We present an integrated workflow that involves broadband reprocessing, high-resolution model building, and depth domain inversion, aiming to reduce some of the uncertainties of the Cook reservoir, located in the West Central Graben of the North Sea. Adaptive deghosting and recent noise attenuation techniques are used to optimize the value of the heritage seismic data. Full waveform inversion is used to reveal the shallow velocity complexity and compensate for seismic distortions beneath. Multilayer tomography is used to resolve the deeper velocities, incorporating checkshot constraints to guarantee sensible borehole ties. A preliminary depth domain inversion suggests that low acoustic impedance values may be due to irregular illumination rather than a change in petrophysical properties. The products from this streamlined strategy will facilitate a new reservoir characterization and support future geohazard analysis.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 207C (Anaheim Convention Center)
Presentation Type: Oral
Dynamic changes in the overburden such as geomechanical variation and hydrocarbon migration which occur between the acquisition of 4D surveys influence reservoir monitoring programs and are typically not compensated for with current industry time-lapse workflows. We utilize prestack time-shift analysis for the Central North Sea Shearwater field to interpret observed dynamic overburden signatures in these attributes and propose a relation to 4D anisotropy due to production related stretching and extension. An inversion of the pre-stack time-shift data delineates velocity perturbations in the overburden associated with structural extension effects.
Presentation Date: Tuesday, October 16, 2018
Start Time: 8:30:00 AM
Location: 204C (Anaheim Convention Center)
Presentation Type: Oral
A high level of reservoir depletion (greater than 8,000 psi) has resulted in significant changes to the drilling envelope that has added complexity to the drilling practices required to exploit the remaining reserves successfully. Managed-pressure-drilling (MPD) technology was implemented in conjunction with drill-in liner and wellbore-strengthening technologies to successfully deliver the first well in a redevelopment campaign and prove the techniques required to prolong field life. Shearwater is an HP/HT gas/condensate field discovered in 1988. Primary production is from the Fulmar, a sandstone reservoir with virgin pressure of 15,400 psi and temperatures greater than 360 F. The field came on stream in 2001. The large field-pressure depletion resulted in compaction at the Fulmar formation level and led to mechanical failure of the production liners because of shear deformation.
Managed-pressure-drilling (MPD) technology was implemented in conjunction with drill-in liner and wellbore-strengthening technologies to successfully deliver the first well in a redevelopment campaign and prove the techniques required to prolong field life. Shearwater is an HP/HT gas/condensate field discovered in 1988. Primary production is from the Fulmar, a sandstone reservoir with virgin pressure of 15,400 psi and temperatures greater than 360 F. The field came on stream in 2001.
The uncertainties of overpressure estimation are among the major challenges to the development of deep and hot reservoirs in many sedimentary basins especially with regards to drilling safety and well economics. However, because of the anticipated huge economic benefits of HPHT geological environments, stakeholders in the oil and gas industry consistently seek to have a good understanding of subsurface pressure systems in order to promote safe and sustainable investments therein. Accordingly, information is required to improve the regional knowledge of geopressures and for the calibration of functions aimed at optimising pre-drill pore pressure estimates for future wells. The Central North Sea, with its vast number of HPHT wells, pressure data, drilling information and documented operational experiences in exploration, drilling, development and production activities stands in a good stead as a "geopressure laboratory" for the fine-tuning of pore pressure prediction concepts, improvement of current geopressure practices and ultimately guide investment and operational decisions in the unexplored areas of the basin itself and elsewhere as geological realities could permit. For this reason, this study utilised downhole pressure-related data and wireline logs to evaluate the pressure regimes in the Central North Sea. The approach involved the quantification of overpressures using standard pore pressure prediction methods that make use of the density and velocity logs of mudstones. The results show that the estimated pore pressure profiles are consistent with measured pressure data in the Cenozoic formations, which makes it reasonable to assume that disequilibrium compaction is the cause of overpressure in this shallow section of the wells. Going deeper into the wells, within the sub-Chalk section, typical calibration parameters from log data could not be used to achieve reliable estimates of overpressures as was the case in the Cenozoic section. Remarkably, while it is possible to adjust the Eaton exponents in order to match estimates with measured data, a wide range of exponent values of between 4.0 and 7.0 is however required. The implication is that there is no systematic variation of the Eaton exponents with the amount of overpressure or depth of burial of the sub-Chalk strata.
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.
California is home to many world-class oil reservoirs, including the San Ardo field’s heavy oil Aurignac reservoir, located in the Salinas Basin. Aurignac primary production was initiated in 1949. In the intervening years, a number of enhanced thermal oil recovery methods were employed. An increase in reservoir pressure has made the continuing use of steam-enhanced recovery methods impractical but has created an opportunity for a new strategy. The best reservoir quality and remaining oil volumes are concentrated in laterally continuous sand zones that are on average 20 feet thick. A horizontal well development is attractive due to this combination of sand body geometry and the higher reservoir pressure, along with availability of surface infrastructure and improvements in drilling technology. This new strategy warrants a geocellular model that provides a detailed framework within which to design and prioritize horizontal well paths.
The dataset for the Aurignac reservoir presents some modeling challenges. Due to previous recovery methods and a wide range of log vintages, porosity and resistivity datasets representing original conditions have different areal distributions. Our modeling approach addresses this by creating individual resistivity and porosity models, then populating each control point with a full set of data through the use of extracted pseudocurves. This modeling workflow utilizes an iterative quality control process to identify anomalies and remove artifacts while preserving true formation responses. Core data and other log data are used to support data quality control decisions. Core is also used to calibrate the porosity and oil saturation calculations. Oil saturations are calculated from a basic Archie equation to avoid imposing assumptions that cannot be substantiated. The property model is populated by the outputs of the porosity and saturation calculations and propagated into a structural framework. The property model assumes lateral continuity based on an interpreted shallow marine lower shoreface environment. Core data and modern logs are used to confirm the model-generated saturations. Given an atypical dataset distribution, integrating petrophysics with geologic interpretation yields a robust property model appropriate for planning a horizontal well development.
Increases in high pressure, high temperature (HPHT) drilling campaigns on the continental shelf of Norway and the UK have increased demands for next-generation technology that can deliver borehole measurements, enabling the wells to be drilled and reducing the operator's risk and operational expense. These deep gas development and exploration wells require a dramatic departure from conventional operating envelopes, including pressure, temperature, hydraulics, and formation evaluation capability.