Africa (Sub-Sahara) Kosmos Energy has made a significant deepwater gas discovery off Senegal. The Guembeul-1 well in the northern part of the St. Louis Offshore Profond license in 8,858 ft of water encountered 331 net ft of gas pay in two excellent-quality reservoirs, the company reported. The results demonstrate reservoir continuity and static pressure communication with the Tortue-1 well, which suggests a single gas accumulation. The mean gross resource estimate for the Greater Tortue complex has risen to 17 Tcf from 14 Tcf as a result of the Guembeul discovery, the company said. Kosmos, the operator, has a 60% interest in the well. Timis (30%) and Petrosen (10%) hold the remaining interest. In Salah Gas has started production from its Southern fields in Algeria.
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.
Al Fakih, Abdulqawi (Schlumberger) | Pessanha, Vinicius (Schlumberger) | Aldape, Alberto Gomez (Schlumberger) | Famiev, Robert (Schlumberger) | Ahmad, Bilal (Schlumberger) | Khan, Tauqeer (Schlumberger) | Obari, Wahid (Schlumberger)
It is considered essential to perform cleanout trips before setting or retrieving specific tools inside casing, such as whipstocks and completion packers. Multiple cleanout trips may be required, e.g., when milling a window in a multilateral well, before setting a whipstock, before retrieving a whipstock, etc. This paper explains how the cleanout trips can be combined with setting and retrieving trips to save time and improve efficiency.
Risk and engineering analysis were performed; the need of new and existing technologies such as high- performance string magnets, casing scrapers and a specialized metal catcher was identified. The data from multiple wells is presented to illustrate the reliability of the optimized practices.
This innovative approach has been implemented in over 50 wells, saving a minimum of two days per lateral in each multilateral well, and up to five days per well based on the number of whipstocks and the completion type; moreover, zero failures were recorded to date. The paper also outlines how the process was further improved by adding larger diameter magnets and scrapers above the liner top, to enhance metal recovery, and reach the theoretical metal weight value expected. This new procedure, also contributed to minimize the completion cleanout trips required for smart completion, from 5 runs to 3 runs per well as average. Finally, the paper discusses the HSE incidents exposure reduction due to the reductions of the number of trips, and highlights future improvement opportunities.
The PML (Producer Multilateral) wells are planned with TAM Level 2 to have 6-1/8” open hole multilaterals reservoir sections which are drilled from cased hole. The number of laterals varies from two to five, being four the most common in this field under study (motherbore plus three laterals). Each lateral requires a whipstock to cut a window in the liner and to drill through it. The 7” liner is set at ±8,000 ft total depth across the reservoir and a 9-5/8” casing is set on the top of the reservoir and extends to surface. This type of multilateral well is completed with a multibore selective completion, installed in the 7” liner (Figure 1), allowing the flow rate from each lateral to be adjusted through downhole inflow control valves (ICVs), depending on the water/oil rate values and pressure management needs. The inclination at the window is around 88-90°, and the liner is set in the 9-5/8” production casing, with the liner top approximately 250 ft above the previous casing shoe.
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.
Gasparini, P. (AMRA (Analisi e Monitoraggio del Rischio Ambientale)) | Basco, A. (AMRA (Analisi e Monitoraggio del Rischio Ambientale)) | Di Ruocco, A. (AMRA (Analisi e Monitoraggio del Rischio Ambientale)) | Garcia-Aristizabal, A. (AMRA (Analisi e Monitoraggio del Rischio Ambientale)) | Teofilo, G. (AMRA (Analisi e Monitoraggio del Rischio Ambientale)) | Antoncecchi, I. (MISE-DGS – UNMIG – Ministero dello Sviluppo Economico, BICOCCA – Università di Milano ) | Salzano, E. (AMRA (Analisi e Monitoraggio del Rischio Ambientale), Università di Bologna) | Salatino, P. (AMRA (Analisi e Monitoraggio del Rischio Ambientale), Università degli studi di Napoli Federico II )
AMRA, Research Centre in the field of the Analysis and Monitoring of Environmental Risk, is a permanent structure for the development of innovative methodologies applied to environmental issues. In the last years, AMRA has devoted significant efforts to develop a quantitative framework for multi-risk assessment to support the identification of effective strategies, economically viable, for the mitigation of impacts due to a wide range of risk sources and their possible interactions, considering scenarios of cascading effects. AMRA has participated and led several initiatives to promote theoretical developments of multi-risk approach and to apply this approach to cases of industrial accidents triggered by natural events (Natech). In particular, various research activities have been carried out by AMRA under projects funded by the European Commission (FP6-Na.Ra.S, FP7-CRISMA, FP7-STREST). Among the recent experiences of AMRA there is also the collaboration with the Italian Ministry of Economic Development DGS-UNMIG through the ARGO project (Analysis of natural and anthropoGenic Risks of Offshore platforms).
The general objective of the project is twofold:
In particular, ARGO aims at developing and applying a multi-risk approach to the analysis of Natech events on offshore installations for hydrocarbon extraction.
This paper discusses the principles of the AMRA multi-risk methodology and its applications to industrial sites. After a brief overview of the major natural phenomena that can trigger Natech events, this work focuses on the conceptual framework underpinning the multi-risk analysis applied by AMRA to the probabilistic assessment of Natech events.
Technology integration is not complete without ownership. In light of the numerous challenges associated with deepwater plays all over the world, the most recent generation of ultra-deepwater drillships have more thoroughly considered the integration of managed pressure drilling (MPD) technology into the rigs. In the interest of accelerating technology integration of MPD in deepwater environments, essential equipment that enables the technique and its associated methodologies was recently offered for ownership by service companies to drilling contractors. Two (2) state-of-the-art dynamically positioned (DP3) drillships have successfully integrated MPD via ownership into their rig systems. This paper focuses on the process that was undertaken to realize rig integration for these drilling rigs, as well as on the challenges that were faced and the solutions developed to surmount them. More importantly, it discusses the outcome of the pioneering MPD rig integration projects and the lessons that were learned along the way, so that future projects are able to build on them. Lastly, it covers the substantial advantages and benefits that MPD equipment ownership, instead of traditional equipment rental, brings to the service companies, drilling contractors and operators.