Copyright 2012, Offshore Technology Conference This paper was prepared for presentation at the Arctic Technology Conference held in Houston, Texas, USA, 3-5 December 2012. This paper was selected for presentation by an ATC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract GIS-based software has been developed under the PIRAM (Pipeline Ice Risk Assessment and Mitigation) program for performing pipeline routing and burial analysis for protection against ice keel gouging.
In October 2010, the deepest-set sealed multilateral (ML) junction in the industry was installed at 6900-m measured depth (MD) in Oseberg South Well 30/9-F-9 AY1/Y2. The differential pressure across the junction in the well was expected to be in the range of 250 bar. To meet this pressure requirement, a junction system rated to 370 bar was identified. The high-pressure junction components and entire multilateral system have undergone an extensive testing and qualification program, including several component tests and a full-scale system interface and integration test. A 10 3/4-in. precut window was installed as an integral part of the 10 3/4-in. liner. The plan was to perform the milling operation through this window. A stuck-string incident during the 10 3/4-in. liner installation accidentally caused the liner to drop in the hole. The liner ended up at the wrong orientation, and the window could consequently not be used. The main bore was drilled to total depth (TD) at 8583-m MD, and the 7-in. liner was run and cemented. After the liner perforation, the BL operations started with the installation of an anchor packer and a latch interface assembly (LIA). The milling operation was performed in a two-step operation with milling of a first-pass window by use of a downhole milling machine before installing a whipstock and performing the second-pass milling operation. The lateral branch was drilled to TD at 8258-m MD, and a 5 1/2-in. screen completion was run and dropped off into the 8 1/2-in. open hole. The junction was finally stung into a completion deflector, simultaneously with an openhole seal stinger entering the top of the screen liner in the open hole, tying the branches together. A 6900-m upper completion string with inflow control valves was finally installed to allow for surface control of the two branches. Despite severe drilling problems in the transport sections of the well, the ML operations were deemed successful. Major risk and challenges with this well design involved orientation of the 10 3/4-in. liner (to position the premilled window) at this depth, debris management after milling operations, and general depth control during junction construction. Debris management in particular became essential as the backup ML solution meant milling steel rather than aluminum. Although the two different reservoirs could be drained by two conventional extended-reach-drilling (ERD) wells, this would be a less cost-efficient solution. Furthermore, the construction of an ML well means that the aforementioned challenges drilling the transport sections had to be handled only once. The successful installation at this depth has proved that ML technology is feasible for use in ERD wells, either to improve the total reservoir exposure or to reach multiple targets from one well.
The Lower and Middle Ordovician paleocave systems form an important type of reservoirs in the Tarim basin, China. To better understand the impact of fractures on the paleocave reservoir development, with acquired wide azimuth 3D seismic data, both post-stack volumetric geometric attributes and P-wave azimuthal AVO analysis are applied to characterize multi-scale fracture distributions. In this study, volumetric seismic attributes including dip, discontinuity and curvature are used to identify sub-seismic faults and associated fracture corridors and to describe subtle folds and flexures within the reservoirs. P-wave azimuthal AVO analysis is applied to detecting high angle fractures. Six azimuth-sectored stacks are used to compute P-wave seismic anisotropy from which fracture density and orientation are estimated.
Two major sets of conductive fractures trending northeast and northwest, associated with different tectonic events, are identified using imaging logs from seven wells in the study area. Fractures predicted from geometric attributes and from the P-wave azimuthal AVO analysis are compared. The feasibility of two approaches for characterizing and mapping various types of fractures is investigated. Our results show that geometric attributes can better allow detecting and imaging sub-seismic faults and fracture corridors. The azimuthal AVO analysis allows detecting zones associated with both large scale fracture corridors and small scale diffuse fractures. However, the poor quality data and local geological structures may prevent from using obtained fracture predictions in a quantitative way. Integrating geometric attributes and azimuthal AVO analysis allows obtaining a comprehensive fracture distribution from fracture networks on the corridor scale to diffuse fracture distributions on the small scale. In this paper, case studies are used to illustrate how these two approaches can be integrated to provide a comprehensive multi-scale fracture distributions calibrated with well data and validated against the conceptual fracture models.
An azimuthal seismic study for fault and fracture identification was carried out on a giant onshore carbonate oil reservoir in the U.A.E., Middle East. The seismic reflectivity analysis was performed using advanced independently processed azimuthal sectors from compressional waves. The seismic attributes demonstrated superior capability of defining accurately the detailed reservoir faults and the fracture networks. Although the full azimuthal study achieved excellent results, the azimuthal stacks were observed to sharpen the reservoir subtle structural features. Beside the traditional land seismic data processing, additional challenges were to properly process the seismic data due to the surface topography and the lateral variations in subsurface rock properties. Azimuthal processing successfully demonstrated:
a) Improved fault imaging relative to the available conventionally processed seismic data.
b) Additional information about the seismic anisotropy in the reservoir zones.
The analysis showed encouraging results and a relatively good match to known fault/fracture locations. The successful results of the study suggest that high quality 3D wide azimuthal seismic data with relative true amplitude preservation can be used to identify the fracture permeability pathways in carbonate reservoirs. The azimuthal sectors study and results facilitated the quantification of the presence of faults, and suggest that fractured zones can be identified. Another important procedure in this study is the use of the integrated approach during processing and interpretation. Overall, the results of this Azimuthal Study for fractured carbonate reservoir characterization revealed encouraging outputs and valuable guidelines for similar studies in the future.
This paper presents the workflow and the results of integration of seismic, well and production data on Habban Field to optimize well locations.
Habban Field is located in the Jurassic Marib-Al Jawf-Shabwah basin of Yemen (Block S2). Development targets in Habban Field are fractured Precambrian Basement, Kohlan and Shuqra formations (Middle Jurassic).
Main challenges faced in the Field are Basement heterogeneity, fracture distribution and their connectivity, lateral variation of Kohlan Formation and the overlying salt diapirs/walls hampering the seismic imaging. The difference between a good and a dry well is whether it is encountering main fracture corridors or not. Fracture corridors (along the faults) have limited lateral extent and due to overlying salt diapirs well trajectory optimization is very challenging. Reflection pattern in the Basement is quite chaotic. Therefore, it was important to come up with a workflow to image faults within the Basement so that highly deviated to horizontal wells can be drilled to enhance production and optimize recovery.
In order to address these challenges, wide azimuth 3D seismic was acquired and processed in different azimuths. The study has been conducted using 3D seismic dataset and derived seismic attributes combined with information from thirty one wells including image and production log interpretation. The workflow highlighted the value of G&G integration to better outline uncertainty and to mitigate risks during well locations and trajectory planning. In this contest structural attributes (i.e. Ant-Tracking) have been crucial in order to define and identify the faults zones for optimizing horizontal wells targeting multiple fracture zones.
On the other hand integration of G&G and production data highlights the limitation in defining a one-to-one correlation between seismic, well and production information mainly due to reservoir complexity and scale resolution.
Geoscientists routinely produce reports addressing the impact of proposed, platforms, rigs & barges in general on historical & prehistoric archaeological sites. These reports identify any conditions at the seabed or in the foundation zone where hazardous subsurface features or unstable soil conditions exist & provide guidelines regarding platform & drill site placements.
The principal aim is to reveal the general near-surface geological structure & indicate reflectors which may represent a change in soil characteristics &/or stratigraphy. This requires the correlation of seismic data with soil borings in the vicinity.
Accurate site surveying is crucial for proper rig positioning & to avoid Non-Productive Time. Mishaps with inaccurate rig positioning can cause disastrous consequences on the platform & impact the costs, more importantly, the lives of many.
This paper attempts to have a more sophisticated analysis on the rig move & rig positioning to ensure a 100% safe spud-in operation at all times. It uses qualitative risk based analysis on all the factors involved in the rig positioning which is a new creative approach that has never been done or thought of before.
During planning the positioning of an offshore rig on a high risk, high reward Gas tower many concerns were addressed. Some of the challenges were namely: a remote location but with close proximity to a residential island, movement history records are incomplete & future unconventional requirements need to be done. Furthermore, the particular area of this field is notorious for having numerous pin holes & punch-through woes due to historical barge/rig movements & due the soil being very muddy. Filling it up with sand bags is simply not a viable solution. To safely administer the rig positioning, several steps were taken to ensure a thorough and flawless approach :
• Reviewing the various methods used for positioning a Platform &/or Rig on a new well location, making it ready for operation & performing accurate spud-in with Zero risk.
• Conducting feasibility studies, including optional checks for punch-through resistance and fatigue; such studies have resulted in a "Statement of Compliance Assessment?? for specific locations & led to the idea of issuing preliminary "Certificate of Approval??
• Researching historical vessel movements that may have foundered in the area of interest conducted
• Scrutinizing advanced methods of rig surveying/positioning that allowed ADMA to develop a customized strategy & implement procedures to prepare these moves & guarantee Operation Safely & Quality delivery. This ultimately saved a huge amount of rig time & ample amounts of money.
• Writing up guidelines for sea-bed & sub sea-bed requirements to assess the suitability for locations.
• Reconnaissance of soil conditions is required in order to begin to establish design criteria for the following types of mobile rig and drilling operations:
- Jack-up rigs
-Anchoring of jack-ups for stand-off locations
-Conductor / casing setting for any rig type
-Initial spudding of drilling equipment, including guide-base stability, from any rig type
The normal & standard alignment of rig-tower orientation was not accepted by the contractor or the Insurance Company. It was maintained that with the current existing challenges, it is not possible to position the rig center to centre.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition & Conference held in Abu Dhabi, UAE, 11-14 November 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied.
Some of the most active and high profile hydrocarbon plays currently being explored and developed around the world lie below a salt canopy. Drilling through a thick salt canopy has the potential to provide a faster route to reach a sub-salt objective rather than drilling through the overpressured sedimentary section in a supra-salt mini-basin. Unfortunately, numerous geological factors can complicate the drilling leading to expensive sidetracking or casing operations. Wellbore stability problems, such as unexpected low fracture gradient, are relatively common while drilling close and out of salt structures. Significant savings on drilling costs can be made if potential wellbore stability problems could be identified and avoided in the well planning process. In this paper we present a workflow to improve wellbore stability predictions for drilling through and near salt structures.
Common assumptions in wellbore stability studies on stress magnitude and orientation are not valid while drilling close to a salt body as salt structures create, due to their shape and rheological behavior, a perturbation of the stress field with strong spatial variation of the principal stress magnitudes and orientations. To provide realistic stress input data for wellbore stability predictions, the stress fields around salt structures are simulated using non-linear materials and realistic 3D geometries. The workflow presented in this paper provides an efficient way to create realistic 3D finite-element based geomechanical simulations from these complicated structural data.
The workflow allows for a detailed simulation of the stress field around salt bodies that is new to the hydrocarbon industry and helps to significantly reduce the risk for wellbore failures of increasingly costly wells drilled to exploit, e.g., sub-salt plays in the Gulf of Mexico and offshore Brazil.
Summary A multicomponent (4C) towed-streamer that measures not only scalar pressure wavefields, but also the three components of P-wave particle motion, was proposed by Robertsson et al. (2008). These new measurements may be used to perform joint interpolation and deghosting of the pressure wavefield, and open the possibility to reconstruct the seismic wavefield at any point between streamers using both pressure and the crossline component of the pressure gradient.