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An ultradeep well, as commonly drilled in the Gulf of Mexico, can run up to 35,000 ft of total depth. The pressure at such depths is extremely high, at approximately 22,500 psi. These wells require highly specialized rigs with expensive day rates; therefore, a significant part of the cost to drill and complete a well is the rig time. As such, minimizing the rig time results in significant cost savings. Often, these wells have a high deviation angle and "S" curve, placing the completion packers at the limits of wireline access. Therefore, completion planning is critical for a successful well completion execution and to reduce the rig time and operational risks. One way to eliminate multiple trips is to set the packer using interventionless methods. Many commercial products are available with designs using hydrostatic setting by means of atmospheric chamber(s), pressure pulse telemetry, and hydro-mechanical-chemical devices. However, these are not designed for the pressure demands of ultradeep wells. After careful consideration of the available products, a new high-performance, modular, removable, interventionless high-pressure-rated production packer that conforms with API SPEC 11D1 (2009) V0 validation grade was developed. Under a tight development schedule, the new product was developed to meet the needs of ultradeep well completions. The packer comprises slips for anchoring and elastomeric elements to provide a sealing capability for zonal isolation. A packer setting module was developed to be attached to the bottom of the packer and set the packer by enabling a fixed volume of high-pressure control fluid to flow from the packer setting chamber to the atmospheric chamber through an intricate flow conduit. An analytical calculation was performed to estimate the resistance coefficient for each feature of the flow conduit, which helped to calculate the macro-level flow characteristics (flow rate, overall packer setting time, and setting piston speed) and the micro-level flow characteristics (Reynolds number, differential pressure, kinetic head, and head losses at steady-state conditions) as well as to optimize the setting mechanism design. The same characteristics for transient flow were evaluated using computational fluid dynamics (CFD) analysis. An experimental proof-of-concept test was conducted on a small-scale version of the flow conduit and, to understand and validate the analytical flow behavior prediction and further optimize the flow conduit, an in-situ high-speed data-acquisition monitoring system was designed to record transient behavior at a high rate of 20,000 samples per second. The measured characteristics from the experimental test matched well with the analytical calculations and CFD analysis. Component-level testing was conducted on the packer element to verify element integrity at 15,000- and 20,000-psi isolation differential pressures. The component-level test was successful, enabling further rigorous testing per API SPEC 11D1 (2009) V0 validation grade, and the packer was successfully set at hydrostatic pressures of 5,000 and 27,500 psi and was validated for the full operating envelope in the unplugged condition, with an isolation differential pressure of 15,000 psi and an axial load of 600,000 lbf in a temperature range from 100 to 300°F. As a result, a breakthrough in technology was achieved by developing a high-pressure hydrostatic packer providing interventionless zonal isolation for an ultradeep well.

Integrating a flow control sliding sleeve into a sand screen can provide multiple advantages to the user in controlling the production inflow. Although it does come with an increased completion cost as well as the number of interventions required when its time to operate those valves. Especially in long horizontal wells, this can become time consuming and inefficient. A few technologies exist to address this issue but they are either too complex or require specialized rigging equipment at the wellsite, which is not desirable. As described herein, a unique, fit for application modular sliding sleeve sand screen assembly with dissolvable plugs was developed that eliminates wash-pipe and allows flow from several screens controlled via a single sliding sleeve. Design and field installation of these modular screens is presented in this paper. The new modular sand-screen consisted of an upper joint, modular middle joint, modular middle joint with ICD/SSD (w/ optional dissolvable plugs), and a lower joint, and novel field installable flow couplings between them. The design allowed for any number of non-ICD/SSD screen joints to be connected to any number of ICD/SSD joints in any order. A computer-aided design was followed to achieve all the operational/mechanical requirements, Computational fluid dynamics (CFD) was used to optimize the flow performance characteristics. Prototypes were manufactured and tested prior to conducting successful field trials. The conceptualization and design stage provided several challenges as different ways to achieving modularity and interconnectivity were explored (such as internal to the tubing or external, sealing methods, ease of installation, reliability). Several design calculations were performed to select the most robust design and most suitable solution for the application. Design for manufacturing review, design calculations and CFD analysis helped with the selection of a concept that maximized the flow rates and kept flow velocity under the limit through the critical sections. Dissolvable plugs were used to temporarily close the SSD ports for wash-pipe free installation. The sealing mechanism of plugs was confirmed by differential pressure test up to 500 psi. A valuable, new downhole modular screen design for use w/ICD/SSD providing intervention-less completions without involving complex/expensive technologies is developed, tested and installed. A new, field-proven, modular sand control technology allowing flow from several non-ICD/SSD screen joints to drain into a single ICD/SSD joint, thus eliminating the need to run ICD/SSD on every screen joint in an unconsolidated formation is developed. Dissolvable plug integrated into sliding sleeve ports allowed wash pipe free installation. The technology allows increasing/decreasing the total drainage length at the well site per zonal requirements, thereby reducing costs and improving performance.

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Meeting the production demand in today's market without sacrificing performance of the artificial lift method is critical. Aggressive flowback procedures lead to solids production and unplanned electric submersible pump (ESP) shutdowns because of solids overload. A novel pump protection system has been designed, tested, and installed in the field. The system enhances the ESP life, improves restarts, and reduces downhole vibrations and unplanned shutdown by controlling the solids flowback and sending solids-buildup pressure signals. A comparative study on three ESP wells in the Delaware basin (US) demonstrated the efficacy of the system. The system comprises of an intake sand control screen and valve assembly. The novel stainless steel wool screen acts as a three dimensional (3D) filter capable of filtering out particles of 15 to 600 μm, and the valve assembly activated by differential pressure across the screen creates a secondary flow path to allow cyclic cleanup of the screen. Stainless steel wool screen with variable pore sizes is used as the sand control media for its high efficiency in preventing the flow of most of the solid particles. When the solids build up on the screen surface, the valve assembly opens upon reaching a preset differential pressure to enable flow past the screens and into the ESP and allows sands deposited on the screen surface to fall off. The pump protection assembly was tested at surface and installed in three wells along with downhole ESP gauges measuring pressure, temperature and vibrations after pulling out existing ESP completions. Qualification testing confirmed the opening of the valve assembly after solids buildup on the stainless steel wool screen. It also validated that the deposited sand fell-off from the screen surface after flow diverted through the valve assembly and pressure differential across screen dropped. In the field installations, the run life of the ESPs improved by an average of 35%, with comparable production volumes and slow drawdowns. In addition, the number of ESP shutdowns related to sand and solids was reduced by as much as 75%, improving longevity of electrical components. The success rate of ESP startups after planned and unplanned shutdowns also improved by 22%. The increase in inlet pressure captured via the downhole gauges when the valve assembly opened indicated the sand control prevention and mitigation system was bridged, and ESP replacement should be scheduled to minimize deferred production from a solids-induced ESP failure and to minimize surface solids management costs. The vibration signal data obtained from downhole sensors confirmed the reliability of the system. Overall, results demonstrate that the system designed is successful at increasing ESP run life without detriment to well production performance. The new, field-proven pump protection system along with its components and the completion design substantially increase life of ESP by reducing the number of shutdowns related to sand overload, reducing shutdowns, reducing overall vibrations, increasing the probability of successful start after shut-in, and increasing the performance reliability during fracturing of a neighboring well. Consequently, more wells that are looking to increase the ESP life can now benefit from this technology and increase output.