One of the most common challenges in deepwater environments is hydrate formation during drilling or well testing operations. A hydrate is generated in the presence of a combination of the following four elements: water, natural gas, low temperatures and elevated pressures. The hydrate has the appearance of ice structures and can form very quickly. Hydrates are normally generated during operations such as startup, shutdown, blowdown, and bleeding. In the deepwater oilfields of Brazil, operators have been faced several challenges during hydrate remediation interventions, including:Effectively removing the hydrate plug formed in the riser without damaging the tubing, downhole valves, and subsea tools across the blowout preventerReducing risk of hydrate formation due to unpredictable behavior because the hydrates can be very hard and very strong, holding high-differential pressures, potentially making a projectile of the formerly plugged objectLimiting pressure losses through the umbilical and maintaining injection rates of methanol and monoethylene glycol (MEG)Resuming well testing operations with the least amount of lost rig time. From a drillship, we applied a combination of chemicals pumped through a high-pressure rotating nozzle deployed with coiled tubing (CT). The hydrate plug was breached in less than 4 hr. This cleaning operation effectively removed the hydrate plug and cleaned the tubing, enabling the Operator to resume pressure/volume/temperature testing operations of the deepwater well.

The process of abrasive jet perforating deployed on coiled tubing (CT), fracturing down the CT and casing annulus, and isolation with proppant plugs has proven beneficial in reducing completion costs and improving operational efficiencies in multistage stimulation applications. Unlike conventional plug and perforation techniques, this process can be done in a single trip, allowing the well to be put on production immediately after the treatment because no bridge plugs have to be drilled. However in horizontal well applications, achieving isolation with proppant plugs can be very challenging due to gravity effects, proppant plug integrity concerns, and ease of fracturing the formation. Adding degradable fibers to proppant plugs has proven successful in achieving good isolation between stages in horizontal wellbores. The fibers not only help create bridging at the perforations, but they also keep the proppant from settling to the bottom of the pipe thereby maintaining the integrity of the proppant plug. This approach has been used successfully in several abrasive jetting fracturing treatments in horizontal wells in West Texas and Southeast New Mexico. Well completion times have been reduced from over a week to only two to three days while allowing for more intervals to be selectively stimulated. Initial production results from the wells completed with the new technique have considerable improvement compared to previous stimulation methods.

This study presents the evolution of downhole fiber optics to a new hybrid electro-optical cable for coiled tubing (CT) applications. The optical fibers enable optical communication and distributed measurements such as distributed temperature and acoustic sensing. The electrical layer delivers continuous surface power to downhole tools, eliminating typical battery limitations such as temperature, operating time, and safety concerns. The electrical layer also enables cable telemetry operation of wireline tools. The hybrid cable is composed of several layers: an inner tube protecting the optical fibers, a layer of low-DC-resistance conductors to deliver high voltage downhole, an insulator, and an outer tube that is exposed to the fluids in the CT pipe. This complex cable is packaged with an outer diameter of only 1/8 in. to maintain maximum flow rates achievable through the pipe. Surface and downhole equipment used with the cable are designed to accommodate electro-optical terminations separating the conductors and optical lines. The cable has been manufactured, tested, and installed in CT pipes. The surface and downhole equipment has been designed and certified to operate in both land and offshore environments and tested with multiple families of tools: well intervention tools instrumented with pressure, temperature, depth control, and load sensors; wireline tools, including pulsed neutron generator and flow profiling tools; a multilateral re-entry tool; and an electrically actuated multiple-set retrievable plug. Over 20 runs and 1,000 hours of operation have already been completed without any power or telemetry loss. The system has saved 160 hours of operation time in Middle East from the implementation of the hybrid cable single-reel solution on four jobs that formerly required two CT strings. In the Norwegian continental shelf, the system saved between 24 hours and 32 hours in a single job by eliminating trips to surface to replace the batteries. This new hybrid cable and its associated surface and downhole system provide a single solution for interventions, distributed measurements, and logging. Altogether, they pave the way for significant improvements in well intervention efficiency and open new avenues for more complex and demanding operational workflows.

Pampo was among the first producing fields offshore in Brazil, and it produced through a fixed platform. The maturation of the field and consequent decrease in oil production required a different completion strategy for the operator. The key reservoir, the Macaé/Quissamã, is the prime target for exploitation because it still has substantial oil in place, with good total recovery and actual recovery factors. The development of this reservoir was vital to the survival of the field. Several technical issues exist for developing this reservoir, especially during drilling, because of the high density of wells in the area. Each new well had to be carefully planned to avoid collision with existing wells and also to optimize the reservoir drainage. Several depleted wells have been evaluated to determine whether they should be abandoned and/or substituted. There were limited options for replacing these depleted wells. With collision problems at shallow depth looming as a huge risk, the number of new wells that could be drilled was low. Furthermore, the lack of rigs available for production drilling and the high slot utilization on these platforms provided additional complications. Ultimately, the development of multilateral wells was identified as the most viable solution. From the main bore, once past the critical collision zone, several legs could be drilled to increase the drainage area. Multilateral construction in this scenario is a nontrivial task. It requires the well junction to be placed at an area of high deviation, adding complexity for any intervention work. Nonetheless, the use of coiled tubing for most of the well completion operations proved to be the key enabler in this successful multilateral well development campaign. The versatility of CT technology significantly decreased the time needed for well completions and its other applications. This paper discusses the development, planning, and preparation activities involved with use of the CT in this milestone project. It summarizes the results of the development of the idea and lessons learned from the numerous runs during the completions operation, including CT-conveyed perforating; CT-conveyed logging for cement evaluation; stimulation, featuring the use of isolation tools; and several Stiffline applications. Introduction During the conception phase of this project there were many obstacles that needed careful attention:The position of the ML Junction at a near-horizontal position required the use of CT for a set of tools designed to be used with SlicklineThe changes in the project with the scaling down of the tool in order to fit Petrobras's existing 4" configuration presented a last minute challenge, with many tools being changed to allow for the access to the main bore or the later leg of this ML System. This ML System was designed to be used in a 5" Bore configuration.Given the rig's age, the crane capacity has been scaling down considerably over the years, even during the project execution, with a maximum limitation of 18 tons. Obviously this restricted the use of larger CT diameters, and even with the minimum amount of CT in the reels it was impossible to place the CT Reel on a position to execute these wells were the slots were placed in relation to the crane's maximum reach.The notion that CT was to be used as the main tool to allow wellbore access and to perform the majority of the tasks downhole posed a conceptual challenge, as in general there were not many people within the Client organization who felt CT was the way to execute these tasks.CT Perforating with high angle and large OD Perforating Guns presented a CT damage possibility due to the shock wave travel that could happen during the detonation. Field Description Pampo, located at south part of Campos Basin, is an offshore location, 80 km far from the coast and 105 m water depth was discovered in 1977.

Bijupirá is the first offshore field in Brazil to produce oil for an international operator. Since reaching its plateau production in January 2004, Bijupirá has experienced significant production declines. The bulk of the production in the field mainly comes from four sub-sea wells completed with a horizontal open hole gravel pack (HZOHGP). Analysis of the causes of production impairment suggests likely fines migration and possibly BaSO4 scaling. Scale removal and matrix stimulation treatments were selected as a solution to reestablish productivity. These were performed from a dynamic positioned drillship using CT in the horizontal open hole gravelpacks. The flowbacks were done to the drillship with lift gas supplied from the FPSO. This imposed a very challenging and unique environment for successful implementation. An extensive laboratory testing program was conducted to determine any negative effects of acid on elastometers and metals used in the wells, subsea system and topsides. Reservoir cores combined with a novel geochemical simulation tool helped to select the acid system and volumes for optimum stimulation treatment whilst limiting possible damage to downhole equipment. A continuous acid mixing system was designed specifically for this operation to allow handling large volumes of fluids without the need for a stimulation vessel. Fluids were injected via coiled tubing using a special rotating jetting system to ensure mechanical clean- up and diversion. A flow back process was planned, considering the implications of injecting gas from a FPSO to a well, via gas lift valves- recovering hydrocarbons and spent acid to the drillship. This process proved to be effective in eliminating any environmental impact. This paper describes the whole process including laboratory testing, design, and simulations. Details of the execution phase are given where three scale dissolver and three mud acid treatments were performed with exceptionally outstanding results in terms of execution and production uplift. The combination of offshore, deepwater, FPSO, drillship and coiled tubing, set a milestone in the industry as first worldwide intervention of this kind. Introduction The Bijupirá field came on production in August 2003 and is both gaslifted and water flooded. It is located in 700 meter water depth and produces from 6 horizontal open hole gravel packed wells. After reaching its plateau production early 2004, the Bijupirá oil production rapidly started to decline from an initial 50,000 BOPD to close to 15,000 BOPD in less than two years in part because of increasing watercuts and mainly because of declining well rates. The bulk of this oil production came from just 3 wells BJ-Q, BJ-T and BJ-S which produced near dry oil with watercuts of less than 10%. Their oil production had declined from 40,000 BOPD to 8,000 BOPD. The declines on wells BJ-Q and BJ-T occurred gradually and constantly over time at exponential decline rates of 60% / year, whereas the decline on well BJ-S occurred suddenly during a routine scale inhibition bullhead squeeze, as illustrated in the Figure 1. The bullhead operation itself used chemicals, and procedures that were proven on other wells in the field.