Coiled tubing is used extensively in Colombia as the preferred alternative to conventional workover operations for reasons of costs, logistics, and security. However, wellbore conditions make few jobs "routine" and extensive pre-job planning is required for each well intervention. Even with precautions, unforeseen situations occur that are unique to Colombia. This paper presents an overview of the types of wells in Colombia. Depths, wellbore schematics, formation interval lengths, fluids produced, etc. are given as background information. Wellbore conditions that affect the use of coiled tubing are detailed to show the difference between Colombia and other areas utilizing coiled tubing. A complete description of the types of jobs run in Colombia with coiled tubing is presented along with problems encountered while doing these jobs. The types of computer modeling used to design and implement each job are also given. Two actual case histories are used as typical examples of problems encountered on a daily basis during well interventions as well as the solutions to remedy these problems. A set of guidelines gained primarily through experience in running coiled tubing in Colombia are presented and may help others encountering similar wellbore conditions in other areas of the world. The concluding section of the paper lists the areas requiring more technological advances for running coiled tubing in Colombia. Introduction The Cusiana and Cupiagua fields of Colombia are highly prolific oil producing fields. Most of the gas is re-injected with the oil processed through two plants and then exported by pipeline to the coast of Colombia. The area is highly faulted and tectonically active which presents many drilling problems. These same problems continue into the completion and workover phases of operation, which complicate the use of coiled tubing. The three primary producing zones are the Guadalupe, Barco, and Mirador; as a result of faulting, these zones may repeat in the same wellbore. The zones themselves range from 15,000 to 17,000ft in depth and are highly permeable. The bottom-hole-temperatures vary from 270 to 290 degrees F.(Table 1) The rock is extremely hard and penetration by even the most advanced perforating charges results in short perforation tunnels. In addition, these perforation tunnels are easily damaged by debris being pumped into them, which makes coil intervention rather than bullhead techniques essential. (Table 2) Typical completions for Cusiana and Cupiagua are either packer style or mono-bore. The tubing and liners are 13% chrome varying in size from 4 ½ to 7 in. Tubing and liners for water injectors and gas injectors are primarily 7 and 7 5/8 in. carbon steel. Refer to Figures 1, 2, and 3 for typical wellbore diagrams for oil producers, gas injectors, and water injectors.
This paper describes the design, implementation details, and the added value of deploying a 15 kpsi Multi-Stage Fracking (MSF) system with an open hole (OH) metal expandable packer. The system would be an additional enabler for successful OH MSF system deployment, especially for wells with concerns over wellbore stability (pack off and/or washouts), getting stuck while running with the completion string to the deployment depth and in Extended Reach Drilling (ERD) wells. The system used four (4) stages deployed in a 5-7/8″ open hole with a length of 3,000 ft. The completion equipment was successfully deployed. Rigless activities commenced by fully expanding the packers (with 12,400 psi), before the multistage fracturing was conducted successfully. The slim Outer Diameter (OD), the ability of drill pipe rotation, the 15 kpsi fracturing capabilities in hole size up to 6.5 inches and the lack of internal moving parts like sleeves or mandrels; enabled the system to deliver the fracking capabilities required with challenging OH conditions. The system provided reservoir compartmentalization with 15 kpsi capabilities between different stages, 15 kpsi fracturing capabilities in hole size up to 6.5 inches and slim outer diameter to enable the deployment of the completion string into challenging open hole conditions. Furthermore, the system has the ability of drill pipe rotation to enable the deployment of the completion equipment to overcome any obstruction while running in hole and no internal moving parts, which lessen the mechanical failure risks. The 15 kpsi MSF with metal expandable frac packer system has the following novel features in wells with wellbore stability (washouts) concerns, where the 15kpsi fracturing capabilities in hole size up to 6.5 inches, as well as long seal length. As for wells with wellbore stability (pack-off) concerns, the system provides relatively slim OD, for smoother running and, that, can be helpful in wells with differentially stuck concerns. Also, it provides better reliability and robustness, as there are no internal moving parts.
Following the success of the first installed intelligent completion system in Saudi Arabia in 2004, over 260 Intelligent Completion systems have been installed in a majority of Maximum Reservoir Contact (MRC) Multilateral (ML) wells. These intelligent completion systems have been successfully installed in openhole, expandable liners, expandable sand screen, Extended Reach Drilling (ERD) wells and also integrated with Electric Submersible Pumps (ESP). This technology has led enhanced oil recovery while reducing water production to surface. Water handling cost at surface is reduced by producing less water to surface and also shutting off downhole water production completely. This paper covers some of the case histories of over ten (10) years of design, planning, installation, testing and optimization of intelligent completion systems in Multilateral (ML) Maximum Reservoir Contact (MRC) wells within Saudi Arabia. Production optimization practices and enhancement of production life in carbonate multilateral wells in the world's largest oilfield are also documented. Case histories highlighting how water production was remotely choked back, shut-off and production optimized from identified lateral without any intervention in the well are reviewed. Advantages of intelligent completion technology for multilateral wells and the review of the downhole choke customization process that included design flow area after modelling well data for different flow rates and differential pressures are detailed. This is in addition to the integration of the surface control system to the production supervisory control and data acquisition (SCADA) system which provided real-time downhole pressure and temperature data and remote control of downhole flow control valves during the life cycle of the well. This paper also discusses a closed-loop approach which led to efficient real time production optimization. Performance review of how intelligent completion systems provide selective lateral control, delay water breakthrough, control water production, shut off wet lateral, reduce opex, optimize production, enhance recovery and reduce safety risks thereby minimizing future interventions are documented.
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