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This paper will review the current state of downhole wireless completion technologies. It sets out an optimized strategy for the selection of commercially viable systems and provides a discussion of the technical hurdles that that are still to be overcome Technologies for real-time wireless downhole data acquisition exist but their widespread adoption has been limited. By relying on theoretical calculations and limited reservoir coverage, some operators are basing critical decisions on a limited picture. This could be during the deployment of completions, leading to a failure to reach total depth (TD) or recognize and deal in a timely way with well control incidents or during the production, where quantification of the reservoir parameters is beyond the reach of a single pressure/temperature gauge. This is typically due to a lack of a value calculation for these technologies, and this paper will set out the information needed to improve the decision process. There are a number of key wireless communication technologies that exist commercially for downhole deployment. These are: acoustic, electromagnetic, radio frequency identification (RFID), pressure modulation, and timers. The strengths and weaknesses of each technology will be presented, and it will also be shown how they can be used to complement each other. A number of global case studies will be presented; these will show the successful deployment of these technologies and the benefits that were brought. This information will then be built on to show how a wireless system should be implemented to satisfy the operators requirements within the technical and financial constraints of today's landscape. Finally, it will highlight the technology gaps that exist that hold the industry back from a "perfect" solution.

Gas lift is one of the most appropriate artificial lift methods for Gulf of Thailand (GOT) oil operations. As first described in Chapman, W. R. (2005), Mono-trip gas lift (MTGL) completions have continuously improved since their implementation in the early 2000s, increasing recovery by over 15%. MTGL completions enable marginal or sub-economic new wellhead platforms (WHPs) or infill projects to become economical. To overcome the more challenging wellbore environment in which the current technology is unable to be utilized, alternative technology was trialed in 2019 to enhance the MTGL completion without sacrificing the wellbore designs or reserves.

This paper will portray the development and deployment of remote-activated sliding sleeve devices commissioned for use in a two-stage completion North Sea project. The sliding sleeves are required within the lower completion to provide access to the reservoir, protection to a control line and act as part of the fluid-loss envelope. Remote activation technology has been implemented to the sleeve designs to improve efficiency and introduce operational flexibility. Three variants of sleeves were designed and deployed to facilitate well objectives. The first variant is run-in-hole (RIH) Open to provide a circulation path and subsequently closed post displacement activities. The second variant is RIH Closed and is distributed across the reservoir. These sleeves are remotely opened post Xmas tree installation and provide the tubing/annulus communication for production or injection. The third variant is again RIH Closed, but this is a purely mechanical sleeve to allow further access to compartments or different reservoir units later in the well's life. A variant of open-hole anchor with bypass capability was also developed and tested. Remote-activated sliding sleeves were prototyped and qualified to API 19AC. In addition to the standard requirements of API 19AC, open/close cycles were also performed with lost circulation material-laden (LCM) fluid along with low hydrostatic pressure function testing. This latter testing is to allow for sequential functioning without having to shut in or choke back the well, instead functioning while the well is flowing or even under full operational drawdown. Three wells have been completed to date, two producers and one injector. The RIH Open sleeves have successfully acted as a replacement to a traditional fluid loss valve and the RIH Closed sleeves have allowed zonal isolation, selective water shut-off and reservoir management. The use of open-hole anchors has also been standardised, in producers to support future stimulation operations and in injectors to combat thermal contraction. Across all three wells the RIH Open sleeves have all been actuated successfully via Radio Frequency Identification (RFID) tag carrier or timer and the RIH Closed via pressure sequence and / or timer. The second producer also saw the first implementation of the staged clean-up functionality with sleeves opening at four different intervals over a period of 17 days.

The reliability of subsurface barrier valves has long been an industry problem. This can lead to costly interventions, especially apparent in deep-water subsea markets. This paper describes the world's first deployment of multicycle barrier valves in 2 subsea wells in Australia that uses innovative methods of both remote activation and triggering, that have been previously unavailable on the market, and attain a step change in reliability. The remote activated barrier valves were deployed as part of a subsea gravel pack system. They were initially run in hole (RIH) open as part of the lower completion, then closed mechanically. The valve was subsequently opened via Radio Frequency Identification (RFID) tags and then closed again mechanically to allow the running of the upper completion. Frequency modulated pressure cycles were applied to the well to open the valve and allow the well to flow. The valve functioned exactly as planned, and it was demonstrated that it could be closed multiple times on a semi-sub vessel. The valve was then opened via RFID tags conveyed on wash pipe. This is a much more reliable method when in high debris environments. The valve was opened for the final time via frequency modulated pressure cycles. These are better able to be transmitted through debris and are not affected by other hydraulic events in the well. The hydraulic pump that is used to actuate the tool provides a constant force directly to the ball valve mechanism and is not subject to failures over time like existing gas charges, ratchet mechanisms or springs. The RFID, Mechanical or pressure cycles used to trigger the valve offer a huge increase in operational flexibility that have never been able to be realized with existing technologies.

In the quest to increase production, extended-reach drilling (ERD) has become a popular approach. However, it is recognized that there are challenges associated with ERD wells. Longer and more complicated well profiles incur substantial operational risks during well construction and completion phases. In most cases, conventional completion systems which require well intervention during installation are not suitable for ERD wells. A new generation of completion system is required to address the challenges. While some categories of interventionless equipment, such as intelligent completion systems, have been made available decades ago, these devices carry limitations which often restricted their application in ERD wells. Most of the intelligent completion systems require control lines to operate. The requirement of control lines not only incurs extra cost to operators but also poses difficulties to run these systems into long horizontal wellbores. Radio frequency identification (RFID) technology has emerged as a promising solution in recent years. The RFID technology uses electro-magnetic waves to establish communications with downhole tools, realizing wireless or "control-line-less" operations. The RFID technique adopted by the oil and gas industry utilizes passive tags which can be made in small sizes and at low cost, suitable for downhole applications. A recent field development campaign which adopted RFID-enabled downhole tools has showed the benefits that RFID technology can bring to the industry. In this campaign, the operator required a remote operated liner toe isolation device. The device would need to be run open to allow circulation during deployment of the lower completion and would be remotely closed to create a barrier at the toe after lower completion installation and well fluid displacement. An RFID-enabled remote operated circulating toe sleeve was developed, delivered and deployed.

Successfully deploying a single-trip completion system in a deepwater environment requires an innovative technical solution to address the risks that come with this environment. Following a request from the operator for a deep-water single-trip solution, a number of different system options were proposed. Each system was evaluated against the operator's requirements, and a radio frequency identification (RFID) technology-based system was selected as it offered the greatest flexibility in both activation and contingency methods to meet the demands of the project. It was proposed to hold a 2 stage system integration test (SIT) at a test rig in Aberdeen. The first SIT was performed with a small number of tools that could be setup in different modes to prove the system's logic against the operator's expectations. While this was conducted successfully, a number of learnings and operational optimisations were captured. These were fed into a full-scale SIT, which was deployed at the same test rig. This second SIT involved a complete representation of the single- trip system, and was designed to test the final system logic prior to deployment into an offshore environment. The system was then installed successfully in November 2018, on a subsea well, offshore Nigeria with no intervention. It resulted in an operational time saving of at least 60% over the previous best recorded time for a conventional two-trip completion from the same rig. This represented a step change in operational efficiency and will now be the operator's base case completion methodology as they develop the field further. This is the first time a single-trip completion has been deployed in this fashion in a deep-water, offshore environment. The demonstrable step change in operational time and resultant project OPEX savings, proves that the use of RFID and remote actuated tools within completions offer excellent alternatives to traditional methods.

The reliability of subsurface barrier valves has long been an industry problem. This can lead to costly interventions, especially in deepwater subsea markets. This paper describes the world's first deployment of multicycle barrier valves in 2 subsea wells in Australia. These valves use innovative methods of both remote activation and triggering, previously unavailable on the market, to attain a step-change in reliability. The remote activated barrier valves were deployed as part of a subsea gravel pack system. They were initially run in hole (RIH) in the open position as part of the lower completion, then closed mechanically. The valve was subsequently opened via radio frequency identification (RFID) tags and then closed again mechanically, to allow running of the upper completion. Frequency modulated pressure cycles were applied to the well to open the valve and enable the well to flow. The valve functioned exactly as planned, and it demonstrated that it could be closed multiple times on a semi-sub vessel. The valve was then opened via RFID tags conveyed on wash pipe. This is a much more reliable method when in high-debris environments. The valve was opened for the final time via frequency modulated pressure cycles. These pressure cycles are better able to be transmitted through debris and are not affected by other hydraulic events in the well. The hydraulic pump that actuates the tool provides a constant force directly to the ball valve mechanism and is not subject to failures over time, unlike existing gas charges, ratchet mechanisms or springs. The RFID, mechanical or pressure cycles that trigger the valve offer a huge increase in operational flexibility that have never been able to be realized with existing technologies.

Successfully deploying a single trip completion system in a deep-water environment requires an innovative technical solution to address the risks that come with this environment. Following a request from the operator for a deep-water single trip solution, a number of different system options were proposed. Each system was evaluated against the operator’s requirements, and a Radio Frequency Identification (RFID) technology-based system was selected as it offered the greatest flexibility in both activation and contingency methods to meet the demands of the project. It was proposed to hold a 2 stage System Integration Test (SIT) at a test rig in Aberdeen. The first SIT was performed with a small number of tools that could be setup in different modes to prove the system’s logic against the operator’s expectations. Whilst this was conducted successfully a number of learnings and operational optimisations were captured. These were fed into a full-scale SIT which was deployed at the same test rig. This second SIT involved a complete representation of the single trip system and was designed to test the final system logic prior to deployment into an offshore environment. The system was then installed successfully in November 2018, on a subsea well, offshore Nigeria with no intervention. It resulted in an operational time saving of at least 60% over the previous best recorded time for a conventional two-trip completion from the same rig. This represented a step change in operational efficiency and will now be the operator’s base case completion methodology as they develop the field further. This is the first time a single trip completion has been deployed in this fashion in a deep-water, offshore environment. The demonstrable step change in operational time and resultant project OPEX savings, proves that the use of RFID and remote actuated tools within completions offer excellent alternatives to traditional methods.

It is often stated that necessity is the mother of invention. Never is this proverb more relevant than in the offshore oil and gas environment we currently operate in where real step changes leading to reduced capital and operational expenditure opportunities are sought and embraced by field operators. This paper discusses the pre-job planning, field execution and lessons learned from one such technology that challenged conventional thinking of sand faced completion, casedhole completion and well integrity to successfully deliver a single-trip, interventionless, sand control completion in deepwater Bonga Field, located on the continental slope of the Niger Delta. Convention dictates that the vast majority of offshore completions be run in two and sometimes three trips which routinely takes in excess of eight to ten days to deploy. Given the day rate of high specification rigs capable of drilling in deep water environments, the ability to reduce this time was deemed paramount to the economics of the project. Utilizing a collaborative approach to initial concept design, risk assessment, extensive testing and contingency planning at component and system level, a single-trip, interventionless, sand control completion system was designed and successfully installed. This paper describes the completion architecture, operational sequence and challenges leading to the installation of an interventionless completion. A clearly defined set of deliverables and design principles were drawn up to guide the direction of the project including: successfully deploying the upper and lower completion in one trip, and testing all barriers. Adopting a simple, low risk and high reward design, meeting clients well barrier requirements and utilizing proven cost-effective technology are examples of design principles used. The system was tested and evolved through a number of iterations in an onshore trial well environment on a number of occasions leading to the first successful deployment completed in the second half of 2018, resulting in an average completion installation time of 5 days, versus the average 10 days for deploying multi-trip completions. Details of the successful installations, lessons learned, along with planned future activity are outlined within the body of this paper. While several of the components incorporated in the single-trip system had been run previously in isolation, this paper also discusses the steps taken to facilitate the first full-system approach to the application of radio frequency identification (RFID) enabled tools in the first single-trip, interventionless sand control completion system. Several components within the completion have been equipped with this technology including a multi-cycle ball valve, wire wrapped screens fitted with inflow control device (ICD), remote operated sliding sleeve for annular fluid displacement.

Every field development faces the challenge of keeping capital and operational expenditures (CAPEX and OPEX) within reasonable limits, while at the same time exploring matured or new technology that can achieve cost limit objectives. With the uncertainties, cyclic nature, instability in the oil and gas global investment markets, and the fluctuation in crude oil pricing, operators in energy exploration and production (E&P) industries as well as service providers are constantly looking for better and more efficient cost-saving products and services. The challenge of maximizing hydrocarbon recovery in deepwater completions with minimum investment, while maintaining the highest level of health, safety, and environment (HSE) and service quality is a continual catalyst for new products and service delivery techniques. In the operator’s Bonga subsea field, the conventional completions techniques for all open hole standalone screen (SAS) completion installations are performed in multiple trips. The first trip involves running the lower completion including a gravel pack packer with screen assembly which allows a gravel pack packer service tool and an internal string with a pump-thru wash-down capability to enable toe-heel circulation, packer setting, and testing. The internal string, which is comprised of the packer setting tool, internal wash pipe, and accessories, is recovered after completion of the first trip into the open hole reservoir section. The second trip involves running the production tubing, production packer, downhole gauge mandrel, safety valve, and other completions accessories and landing the production string into the lower completion and on the tubing hanger. The major objectives and drivers for the innovative open hole single trip stand-alone screen completion (STC-SAS) in a deep offshore environment is basically to save rig costs, use proven and emerging technologies, employ completions best practices, reduce exposure of personnel to safety hazards, and reduce non-productive times (NPT). New completions techniques with different services and product providers could pose a challenge in terms of vendor interface management, equipment compatibility, and procedural integration of multiple downhole tools with different operating boundaries and limits. The STC-SAS completions concept in deep water was generated with the operator’s Wells Front End Completion and Well Intervention team in December 2015. This was driven by an opportunity to further reduce well delivery rig time which is at a premium in deepwater subsea completions. The average completions time in the field stood at 10 days per 10,000 ft well. The group was challenged to further improve the well delivery time. However, there was no benchmark as the industry data showed that a single trip open hole stand-alone screen completion had not been installed globally in a deep water subsea environment. This paper presents the evolution of the completions design, the critical challenges in the service companies management, downhole equipment interfaces, operational steps, risks, and the lessons learned during the job execution that led to the successful installation of the industry’s first single trip open hole sandface STC-SAS in a deep water environment.

Every field development requirement is to keep the capital and operational expenditures (CAPEX and OPEX) within reasonable limits, at the same time exploring matured or new technology that can achieve cost limit objectives.With the uncertainties, cyclic nature and instability in the oil and gas global investment and the fluctuation in crude oil pricing, operators of the exploration and production (E&P) energy industries and service providers are constantly looking for better and more efficient cost saving products and services. The challenge of maximizing hydrocarbon recovery in deep water completion with minimum investment, while maintaining the highest level of Health Safety and Environment (HSE) and service delivery always leads to new products and service delivery techniques.In the operator's Bonga subsea field, the conventional completions technique for all open hole Standalone Screen (SAS) completion installations are performed in multiple trips. The first trip involved running a gravel pack packer with screen assembly which allows a gravel pack packer service tool and an internal string with a pump thru wash-down capability enable ease of deployment, toe-heel circulation, packer setting and testing. The internal string which comprises of the packer setting tool, internal wash pipe and accessories is recovered after completion of the first trip into the open hole formation section. The second trip involved running the production tubing, production packer, downhole gauge mandrel, safety valve and other completions accessories and landing the production string on the tubing hanger.The major objectives and drivers of the open hole Single Trip Stand-Alone Screen completion (STC-SAS) in deep offshore environment is basically to save rig costs, use proven and emerging technologies, employ completions best practices, reduce exposure of personnel to safety hazards and of course reduce Non-Productive Times (NPT). New completions technique with different services and product providers could pose a challenge in terms of vendor interface management, equipment compatibility and procedural integration of multiple downhole equipment with different operating boundaries and limits.The single trip stand-alone screen completions concept in deep water was generated by the operator's Wells Front End Completion and Well Intervention team in December 2015. This was driven by an opportunity to further reduce well delivery rig time which is a premium in deep water subsea completions. The average completions time in the field stood at 10 days per 10,000ft well. The group was challenged to further improve the well delivery time. However, there was no bench mark as the industry data showed that a single trip open hole stand-alone screen completion had not been installed globally in deep water subsea environment.This paper presents the evolution of the completions design, the critical challenges in the contractor management, downhole equipment interfaces, operational steps, risks and the lessons learned during the job execution that led to the successful installation of the first single trip open hole sandface STC SAS in deep water environment.

Deepwater operators continually face technical and environmental challenges to drilling and completing wells safely and efficiently. To address both current and future challenges, the industry has leveraged radio frequency identification (RFID) technology to reduce risk, rig time, and nonproductive time (NPT) and to perform operations that traditional tools cannot perform. RFID technology has been integrated into drilling and completions tools to improve performance and reduce risk for offshore operations, such as drilling underreamed holes, spotting lost circulation materials, setting packers, opening stimulation sleeves, and performing subsurface reverse cementing. These tools use RFID tags released from the rig floor to enable downhole hydraulic power units (HPUs) to operate the tools. This paper describes criteria for selecting RFID-enabled tools rather than traditional tools, integration of RFID tools with operations, and value-added features enabled by RFID. Contingency, safety, and risk assessment factors are discussed, along with case studies validating performance and suitability of selected RFID tools.Three case studies describe how RFID solutions for drilling and completions were selected and applied in high-cost environments to address specific challenges and job objectives. Design and bench testing of RFID tools to enable future subsurface reverse cementing operations are also covered.The first case study describes an RFID lower-completion system that was successfully deployed into a southern North Sea extended-reach well. The system enabled remote control of flapper isolation valves and remote operation of stimulation sleeves to access the reservoir, which aimed to eliminate the need for intervention between treatments and ultimately improved fracture cycle time and reduced risk.In the Gulf of Mexico, an RFID drilling underreamer was used to set a liner shoe precisely at the casing point and eliminate a dedicated hole-opening run that would have been needed with traditional underreamers. The 8 1/2-in. hole section was drilled; but losses prevented the mechanical reamer from opening. Therefore, the 650-ft hole section was drilled to TD using the bit only. To eliminate multiple trips to take pressure samples and underream the hole section to 9-7/8 in., an RFID underreamer was placed below the measurement-while-drilling/logging-while-drilling (MWD/LWD) equipment. After pressure measurements were taken, the underreamer was actuated with RFID tags to enlarge the entire 650-ft openhole section with less than a 13-ft rathole.In the last case study, an RFID circulation sub was deployed above other bottomhole assembly (BHA) components, including an RFID underreamer and a conventional ball drop underreamer. This configuration enabled the operator to ream out the 22-in. cemented show track, underream the openhole section, and efficiently clean the wellbore at total depth. Because of BHA and standpipe pressure limitations, the RFID circulation sub was used in a split-flow application to bypass a percentage of the total flow to allow for a higher downhole flow rate. The sub helped to achieve high flow rates, high annular velocity, and turbulent flow, which contributed to better hole cleaning and improved wellbore integrity.Selecting the best tools and technology for specific applications results in streamlined applications and reduced operational risk. The methodology for selection, design, planning, and implementation of RFID drilling and completions tools identifies when RFID technology can be beneficial to deepwater operations.

Driven by ever increasing associated costs, the industry has long sought an enabling technology to expedite hydraulic fracture cycle times in high cost environments such as offshore. Remotely operated completion tools have been proven to provide these efficiencies and can positively influence the viability of these multi-zone stimulation projects.This paper will focus on the planning and execution of an offshore North Sea lower completion to present a methodology to remotely access and isolate the reservoir during multi-zone stimulation operations. Innovative technologies utilized in this case study are presented which effectively minimize the cycle time of the stimulation process while providing a high level of contingencies to account for a panoply of scenarios which could occur through-out the operation.There are several techniques and methodologies which have been deployed to efficiently stimulate multi-zone, horizontal wells in offshore locations such as those found in the North Sea; technical papers such as (Langford 2014) discuss these in detail. This paper will describe the successful deployment of a novel lower completion system into a Southern North Sea extended reach well in June 2015 which targeted the a sandstone formation of the Lower Permian (Rotliegend) strata.The selected remotely operated lower completion system incorporates multiple communication methods on-board to permit remote functioning of flapper isolation valves, to compartmentalize the reservoir internally, and remote operated stimulation sleeves to access the reservoir, which effectively eliminates the need for intervention between treatments, ultimately improving fracture cycle time and reducing risk while providing operators with realistic contingencies in the event of screen-out.

One of the main challenges in the oil industry is to reduce well intervention costs. This paper will explain the planning and execution of an application in the Middle East in which Radio Frequency Identification (RFID) technology has been incorporated into a Circulating Toe Sleeve (CTS) to close and operate the tool remotely. Using the remotely activated CTS tool eliminates the need for additional intervention equipment and subsequently reduces the operational cost and risk involved in isolating and testing liners in Extended Reach Drilling (ERD) wells. The remotely activated CTS will be located at the toe of a plugged Pre-Perforated Liner (PPL). The RFID CTS tool will be run open so that the liner can be circulated in. When the liner assembly is at the desired depth, it will be activated either by circulating RFID tags to the tool or allowing a timer to elapse. Once the CTS has been closed, it will prevent communication between the liner and the wellbore, thereby functioning as a barrier and allowing the liner assembly to be pressure tested. The use of a standard circulating toe sleeve to provide liner isolation would typically result in significant costs and risks for the operator. These could be incurred in intervention time, additional service personnel on location, and budgeting for the risks associated with intervention. In ERD applications it may not be technically possible to provide an intervention solution to all parts of the well, especially the toe section. The use of a remotely activated CTS can reduce all of these considerations and make ERD wells economical and technically feasible. The potential savings this technology can bring increase by an order of magnitude when applied offshore/subsea.

With the downturn in oil price and recent reduction in drilling activity, especially in high-cost environments, the industry is increasingly looking to save time, cost, and risk throughout all drilling and well operations. Conventional completion operations are being challenged to identify possible ways of reducing time and cost. To address this, the industry is adopting new technologies and methodologies to reduce risk, rig time, and nonproductive time (NPT) and to conduct operations in way that traditional tools do not allow. This paper focuses on the first subsea deployment of a remotely activated annular safety valve (ASV) in a deepwater well located in the Norwegian sector of the North Sea. ASVs are traditionally set by one of four methods: a dedicated setting line to surface, applied tubing pressure, applied annulus pressure, or the shifting of a mechanical sleeve, which allows communication to a setting chamber. This paper describes an approach for running the ASV that requires no dedicated setting line and is initially insensitive to tubing pressure; this facilitates the full testing of the completion prior to setting the ASV packer. Using existing rig infrastructure, a frequency modulated pressure cycle is sent from surface to command a sleeve to move and allow communication with the setting chamber. The ASV packer is then set and tested. The first subsea deepwater installation of the ASV was completed in August 2016, and this method of deploying the ASV provided several advantages over traditional methods.

With the constant push to save rig time and costs, the industry is looking to technology to provide these benefits whilst maintaining the same operating standards and risk mitigation. Radio Frequency Identification (RFID) technology provides the means to remotely actuate downhole completion tools, thus reducing rig time by mitigating the requirement for intervention runs and the risks associated. This paper will focus on an application of RFID technology to enable an operator to eliminate an intervention run or intermediate liner into a 10,000-ft reservoir section in the North Sea. The case-study well has pre-perforated liner in two zones—a 4-1/2-in. lower zone and a 7-in. upper zone (Fig. 1). These zones are isolated with swellable packers and pressure-actuated annulus packers. The typical procedure is to straddle the annulus packers individually using an inflatable plug, but setting the lower annulus packer incurs additional risk while running in the horizontal for an extended distance. In this application the client is to use the RFID Reservoir Isolation Valve (RIV) to eliminate an intervention run to set an annulus packer. The RFID RIV provides the means to isolate the lower reservoir section and to provide a closed system to apply tubing pressure against. Figure 1 Well schematic

Driven by ever increasing associated costs, the industry has long sought an enabling technology to expedite hydraulic fracture cycle times in high cost environments such as offshore. Remotely operated completion tools have been proven to provide these efficiencies and can positively influence the viability of these multi-zone stimulation projects. This paper will focus on the planning and execution of a recently completed offshore North Sea lower completion to present a methodology to remotely access and isolate the reservoir during multi-zone stimulation operations. Innovative technologies utilized in this case study are presented which effectively minimize the cycle time of the stimulation process while providing a high level of contingencies to account for a panoply of scenarios which could occur through-out the operation. There are several techniques and methodologies which have been deployed to efficiently stimulate multi-zone, horizontal wells in offshore locations such as those found in the North Sea; technical papers such as (Langford 2014) discuss these in detail. This paper will describe the successful deployment of a novel lower completion system into a Southern North Sea extended reach well in June 2015 which targeted the a sandstone formation of the Lower Permian (Rotliegend) strata. The selected remotely operated lower completion system incorporates multiple communication methods on-board to permit remote functioning of flapper isolation valves, to compartmentalize the reservoir internally, and remote operated stimulation sleeves to access the reservoir, which effectively eliminates the need for intervention between treatments, ultimately improving fracture cycle time and reducing risk while providing operators with realistic contingencies in the event of screen-out.

Deepwater operators continually face technical and environmental challenges to drilling and completing wells safely and efficiently. To address both current and future challenges, the industry has leveraged radio frequency identification (RFID) technology to reduce risk, rig time, and nonproductive time (NPT) and to perform operations that traditional tools cannot perform. RFID technology has been integrated into drilling and completions tools to improve performance and reduce risk for offshore operations, such as drilling underreamed holes, spotting lost circulation materials, setting packers, opening stimulation sleeves, and performing subsurface reverse cementing. These tools use RFID tags released from the rig floor to enable downhole hydraulic power units (HPUs) to operate the tools. This paper describes criteria for selecting RFID-enabled tools rather than traditional tools, integration of RFID tools with operations, and value-added features enabled by RFID. Contingency, safety, and risk assessment factors are discussed, along with case studies validating performance and suitability of selected RFID tools. Three case studies describe how RFID solutions for drilling and completions were selected and applied in high-cost environments to address specific challenges and job objectives. Design and bench testing of RFID tools to enable future subsurface reverse cementing operations are also covered. The first case study describes an RFID lower-completion system that was successfully deployed into a southern North Sea extended-reach well. The system enabled remote control of flapper isolation valves and remote operation of stimulation sleeves to access the reservoir, which aimed to eliminate the need for intervention between treatments and ultimately improved fracture cycle time and reduced risk. In the Gulf of Mexico, an RFID drilling underreamer was used to set a liner shoe precisely at the casing point and eliminate a dedicated hole-opening run that would have been needed with traditional underreamers. The 8 1/2-in. hole section was drilled; but losses prevented the mechanical reamer from opening. Therefore, the 650-ft hole section was drilled to TD using the bit only. To eliminate multiple trips to take pressure samples and underream the hole section to 9-7/8 in., an RFID underreamer was placed below the measurement-while-drilling/logging-while-drilling (MWD/LWD) equipment. After pressure measurements were taken, the underreamer was actuated with RFID tags to enlarge the entire 650-ft openhole section with less than a 13-ft rathole. In the last case study, an RFID circulation sub was deployed above other bottomhole assembly (BHA) components, including an RFID underreamer and a conventional ball drop underreamer. This configuration enabled the operator to ream out the 22-in. cemented show track, underream the openhole section, and efficiently clean the wellbore at total depth. Because of BHA and standpipe pressure limitations, the RFID circulation sub was used in a split-flow application to bypass a percentage of the total flow to allow for a higher downhole flow rate. The sub helped to achieve high flow rates, high annular velocity, and turbulent flow, which contributed to better hole cleaning and improved wellbore integrity. Selecting the best tools and technology for specific applications results in streamlined applications and reduced operational risk. The methodology for selection, design, planning, and implementation of RFID drilling and completions tools identifies when RFID technology can be beneficial to deepwater operations.

Mature fields present major challenges for drilling and the installation of casing and liners. These fields typically exhibit depleted intervals with narrow pressure windows located in the same hole interval, posing unique challenges for installation and cementing of casings or liners. Fluid losses in the depleted intervals coupled with the inability to manage the annular fluid level can lead to differential sticking and stuck pipe scenarios while using conventional drilling and casing installation methods. Furthermore, even if the casing or liner is landed at its planned depth, the subsequent cementing operation offers its own challenges with little chance of a positive outcome with conventional cementing methods potentially resulting in significant non-productive time (NPT). These challenges provide fertile ground for the development and implementation of unconventional drilling technologies such as drilling with liner (DwL) and managed pressure drilling solutions to enable operators to meet their well construction objectives where conventional methods have little chance for success. The DwL process allows a hazard interval to be isolated and cemented in a single trip resulting in less risk and exposure compared with the use of conventional drilling methods. This technology has found its niche in wells where zones must be drilled which have a high probability of hole problems such as fluid loss, narrow drilling margins, depletion and instability, leading to excessive NPT. Still, the subsequent cement job typically involves pumping cement through the casing bit into the liner-open hole annulus with the hope of obtaining the required formation integrity test (FIT) value while also satisfying annular and zonal isolation requirements A North Sea operator has experienced sustained annulus casing pressures in wells in a mature chalk field. This is due to lack of cement isolation and cement channeling after a 9-5/8 in. drilling liner is drilled through a pressured shale overburden interval into a depleted chalk interval with the liner typically becoming stuck. Conventional liner cementing methods were not providing the necessary hydraulic or mechanical isolation over the life of these wells due to the very narrow pressure windows exposed in the drilling liner interval and the lack of ability to rotate the liner above the liner stuck point during cementing. An international oilfield service provider collaborated with the operator and together designed a cementing solution using strategic deployment of multiple remotely operated cementing port collars on the drilling liner to meet the required cementing objectives. Also included on the drilling liner are a metal expandable annular casing packer and hydraulic casing swivel designed and configured to be fully compatible with the planned hydraulic DwL system. This paper will present the DwL system design process along with the related procedures enabling the cementing port collars to be remotely activated with the liner having the ability to be rotated above the stuck pipe section and cementing operations commencing directly after reaching total depth.

With the increase in drilling activity in new subsea and deep water exploration and development, a reliable means of intervention-less completion technology has become a major consideration in helping to reduce operational risk and achieve economic exploitation of new hydrocarbon reserves. Although intelligent completion methods have been in use for some time, the communication system they require can be expensive and time consuming and the need for a simpler, more cost effective, method of intervention-less well completion and management is clearly an attractive option. To simplify the completion process, a new system has been developed which uses the well tried and trusted communication method known as Radio Frequency Identification (RFID). RFID is a reliable well proven technology which is used in countless applications in daily life; however its applicability to the oil and gas industry is only now beginning to be recognized. In this system tubing mounted control modules, which are capable of performing a number of key completion operations, are activated by simply dropping and pumping down RFID tags or, where pumping down is not possible, by the application of pressure cycles. This system consists of several primary components as follows: Battery powered control module with antenna and processors, motor, pumps and closed hydraulic reservoir.A circulating control valve functioning as a sliding sleeve.A hydraulic set packer.A barrier valve. Using these modules all the operations involved in an upper well completion can be performed free of interventions. This paper will give an introduction of RFID technology and present operational mechanism in detail for key accessories of this new intervention-less completion system; and also display one typical logic application of sequence of operations for a new intervention-less upper completion system.