Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Successful Offshore Coiled tubing Well Intervention in Mega-Reach Wells in the Russian Caspian: A 4-Well Case Study
Burdin, K.. (Schlumberger) | Mazitov, R.. (Schlumberger) | Bravkov, P.. (Schlumberger) | Lobov, M.. (Schlumberger) | Kichigin, A.. (Schlumberger) | Stepanov, V.. (Schlumberger) | Eliseev, D.. (Lukoil-Nizhnevolskneft) | Zemchihin, A.. (Lukoil-Nizhnevolskneft) | Byakov, A.. (Lukoil-Nizhnevolskneft)
Abstract Korchagin oilfield is located in the northern part of the Caspian Sea. Drilled wells are mega-reach (MD/TVD ratio greater than 3.0) with measured total depth (MD) up to 23,622 ft [7,200 m] and vertical depth of only 5,118 ft [1,560 m]. This presented a great challenge for coiled tubing (CT) well intervention even with the help of state-of-the-art hydraulic tractors. Limited working area, weight restrictions, challenging well geometry, completion features and lack of experience in offshore CT operations in the North Caspian Sea, required complex pre-job activities to optimize job design, select proper downhole tools and prepare a robust layout plan. This paper will illustrate the project preparation challenges, on-the-job troubleshooting and workflow, supported by the well case studies and results from the first CT operation in Northern Caspian Offshore. Lessons learned from the project, where all defined objectives were achieved with zero HSE (health, safety and environment) incidents, were also captured to assist in future campaigns with similar operational environment.
- North America > United States (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
Abstract A carbonate field in the northeastern part of Saudi Arabia is undergoing major field development. 75% of the wells are extended reach wells (ERWs) or mega-reach wells. Reservoir pressure maintenance is essential, which is why peripheral water injectors and oil producers (OPs) require matrix stimulation to achieve developmental targets. The field's offshore portion contains platforms on several developed wells longer than 17,000 ft (i.e., beyond the natural reach of coiled tubing [CT]) and with an average of 6,000 ft. laterals or openhole sections. Provision of stimulation solutions for these wells drilled with mud and completed with fluids containing CaCO3 requires optimization to expeditiously complete the jobs with minimal lost time. Nonrig remedial operations are preferred compared to drilling or workover rigs, primarily for economic and technical reasons. The rigless interventions offshore present unique optimization challenges because of several surface and sub-surface complexities. The use of a CT jackup barge with a support vessel connected by flexible hoses eliminated the need for a rig for stimulation purposes. Flexibility was crucial, such as when accommodating procedural changes for CT reservoir reach. This paper discusses the methodology, technologies and practices resulting from goals to identify cost-effective means to stimulate offshore wells to remove reservoir damage and improve well performance after drilling operations, and before putting the wells on service. The optimized solution has allowed integrated CT (pumping, e-line, slickline) and testing services on 40 wells using large treatment fluid volumes. Customized CT stackup has resulted in improved logistics and reduced idle time between treatments. Well performance improvements up to 200% have been recorded. This translates to improved operational safety because human exposure to equipment handling is significantly minimized. The success recorded in the nonrig interventions for producers and injectors indicates that rigless CT stimulation can provide opportunities for operators to yield optimum benefits when developing a major field.
Abstract Chevron's portfolio of subsea assets in the Gulf of Mexico is poised to more than double in the next 5 years starting with First Oil of Jack/St. Malo, the development of Buckskin Moccosin, and the expansion of its exisiting Tahiti and Blind Faith subsea development assets such as Tahiti 2 and Blind Faith 2. Subsea well recovery rates typically underperform when compared to their surface well counterparts. One significant factor is the relatively high access costs for subsea well intervention. Without frequent intervention to maintain well performance, a lot of barrels are left behind. At Blind Faith Chevron is investigating platform-based intervention alternatives that dramatically improve economics by reducing or eliminating the need for vessel-based intervention. A key enabler is the Coiled Tubing Intervention Riser (CTIR) system that creates a direct vertical access point to the flowline riser from the platform. With the flowline accessible by coiled tubing, services such as acid stimulation, artificial lift, hydrate remediation, etc. become feasible. The reach of the coiled tubing is limited to the pipeline end terminations of the riser flowlines making direct vertical access to the subsea trees still a job for the large, expensive vessels. The CTIR system does not replace the need for vessel-based intervention, but it does support some well intervention options.
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 727 > Tonga Field (0.94)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 727 > Tahiti Field (0.94)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 727 > Caesar Field (0.94)
- (16 more...)
Abstract An operator working in the North Atlantic off the coast of Newfoundland, Canada required a downhole barrier to permanently abandon a set of depleted perforations. Platform limitations restricted the use of traditional methods to abandon the zone located in a nearly horizontal lateral well. The operator elected to set a high expansion inflatable bridge plug on wireline in a highly deviated section and spot cement on top of it to abandon the zone. There were several challenges involved in this application including the requirement for the bridge plug to expand by more than 200% of its run-in diameter due to wellbore restrictions and deviation. E-line was required to provide power for the wireline tractor because a coiled tubing unit could not access the well slot due to the positioning of the rig on the platform. Additionally, the bridge plug had to withstand a 3,000 psi differential pressure test and hold for several weeks without the aid of cement until coiled tubing could be deployed to place cement on top. The plug was successfully set and held the required pressure. Three weeks after, the platform derrick was moved to another slot and coiled tubing access was again available. The plug was again tested to 3,000 psi and cement was placed on top of it to establish a permanent barrier. A high expansion inflatable bridge plug setting system run in conjunction with a wireline tractor provided an optimal solution for this application. Using this inflatable bridge plug setting system in conjunction with a wireline tractor represented substantial savings in rig time and operational costs. The operator was able to perform all necessary integrity tests to confirm hydraulic isolation and successfully abandon the zone. The bridge plug deployment system is capable of pumping downhole wellbore fluids to set the plug without a coiled tubing unit or pumps on location. E-line was used to support the tractor through high deviation however; the bridge plug deployment system can alternatively be deployed on slick-line or with a coiled tubing tractor.
The First Implementation of Well Interventions by a Full Catenary Coiled-Tubing System With a Dynamic Positioning Vessel with Compensated Gangway
Wattanasuwankorn, R.. (Boots & Coots, A Halliburton Service) | Ashby, S.. (Boots & Coots, A Halliburton Service) | Hammer, F.. (Boots & Coots, A Halliburton Service) | Long, N.. (Shell) | Song, Y.. (Shell) | Ahmed, J. A. (Belait Shipping)
Abstract An offshore operator in Brunei faced the challenge of increasing the injectivity in water-flooded fields to improve hydrocarbon production. The solution chosen was to use a stimulation vessel with coiled tubing (CT), nitrogen, and pumping capability to perform well interventions to achieve the injection targets. The operation faced challenging offshore weather conditions, limited platform access, lack of crane facilities, aging offshore facilities, and had to provide an emergency disconnect system, while improving the operational efficiency from existing methods. The stimulation vessel was used in conjunction with some new concepts to the CT offshore operation. These novel concepts included using a full catenary system for CT operations, a dynamic positioning vessel, a knuckle boom crane, and a heave compensated gangway. The full catenary system was selected for the CT operation to minimize lifting hazards, improve equipment installation lead times, and improve the stimulation vessel operating efficiency. The dynamic positioning vessel eliminated anchoring requirements and provided enhanced efficiency for evacuation and approach to offshore facilities. The knuckle boom crane provided the capability to lift in different angles for equipment placement in difficult positions, even underneath a platform helideck. The heave compensated gangway provided extremely safe transfer of personnel between the stimulation vessel and the offshore facilities. It also provided a safe emergency response and evacuation facility in the event of sudden severe weather, platform emergency, or worsening sea conditions. The advantages and benefits of using these concepts for offshore operation have resulted in a significant improvement in terms of operational efficiency and safety for the stimulation vessel.
- Asia > Brunei (0.35)
- North America > United States (0.28)
Abstract In June 2010, as part of an operation in a producing well, offshore eastern Canada, a junk basket on wireline tagged its depth and became stuck. The bottomhole assembly (BHA) was disconnected and left in the well. When the wireline was back at surface, scale was determined to be the reason for getting stuck. This became more evident after an attempt was made to bait the fish, which was unsuccessful because loose scale had settled on top of the disconnected tool. A run was made with a lead impression block (LIB) to understand better the fish neck, but it returned with no impression. Previously, in 2005, naturally occurring radioactive material (NORM) was detected in this well, having been observed on logging tools returned back to surface. Similarly, a few years later, NORM scale concerns appeared in another producing well on the platform. Due to the inability to handle large amounts of NORM (mostly loose scale) on surface, no intervention work to date had been performed on this platform. The proposed solution was to perform a scale removal operation using coiled tubing (CT). Initially, a pilot hole was drilled with a motor and mill, but the main focus was the use of a 2 7/8-in. scale-removal tool that employed jetted beads. For optimal pump rates and suspension capabilities, a specific gelled fluid system was recommended. A shaker system was sourced to remove and contain solid cuttings on surface and to recycle the gelled fluid on surface by using two large fluid containment tanks. The operation was completed successfully and without any issues or concerns. Client was able to recover the slot for future sidetrack drilling, which is a priority on a fixed platform.