Dual-Gradient Drilling and Riserless Mud Recovery Technology: A Review of Principles, Progress, and Challenges

Abstract

Deepwater drilling operations face critical challenges including narrow pore-fracture pressure windows, wellbore instability, and environmental concerns from drilling discharge. This paper presents a comprehensive systematic review of Riserless Mud Recovery (RMR) technology, tracing its evolution from its conceptual origins to its current applications, critically analyzing its technical limitations, and identifying future research directions. A systematic literature review was conducted covering peer-reviewed journals, SPE/IADC conference proceedings, industry technical reports, and independent academic studies from 1990 to 2025. Databases searched included Web of Science, Scopus, OnePetro, and Google Scholar, supplemented by Derwent Innovation Index for patents. After screening over 100 publications, approximately 60 references were selected following a two-step process excluding vendor-only promotional materials. Key findings reveal the following: (1) RMR technology has evolved through three distinct hardware generations—flexible hose systems, steel-pipe return lines with tandem pumps enabling deepwater breakthrough to 1419 m, and hybrid riser configurations for conceptual designs beyond 3000 m; (2) documented field benefits include 70% drilling fluid reduction, 9 days’ time savings per well, and successful mitigation of shallow geohazards across more than 1000 global well applications; (3) integration with casing-while-drilling and managed pressure cementing has enabled record-breaking performance of 1710 m in a single run; (4) independent academic validation confirms fatigue mechanisms affecting mud return lines; (5) systematic failure mode analysis identifies critical reliability issues in suction hoses, seals, and control systems; (6) quantitative economic analysis shows RMR cost-effectiveness depends on water depth, geological conditions, and environmental regulations. RMR technology has matured into a reliable drilling solution, yet its continued evolution requires addressing hardware limitations, developing dedicated well-control protocols, expanding to ultra-deepwater and emerging applications, and integrating digitalization for real-time optimization.

1. Introduction: Common Challenges in Deepwater Drilling and the Driving Forces for Technological Innovation

The strategic advancement into deepwater and ultra-deepwater domains was recognized as a critical pathway. This path was pursued for both securing energy supply and advancing Earth science exploration. Marine hydrocarbon resources are known to be abundant. However, deepwater drilling operations were confronted with a series of severe challenges. These included harsh environmental conditions, narrow formation pressure windows, poor wellbore stability, and the requirement for additional casing strings [1,2,3,4]. For the oil and gas industry, deepwater regions have long been regarded as holding immense potential. This potential was seen as crucial for future global resource reserves. Consequently, intense international competition was driven by this prospect. Continuous technological evolution was also stimulated. Concurrently, the scientific community, exemplified by the Integrated Ocean Drilling Program (IODP), was dedicated to a specific goal. The retrieval of geological records from deepwater areas was pursued. The targeted water depths for such scientific endeavors often exceeded those of routine industrial operations. A common and formidable reality was faced by both industrial and scientific endeavors. It was acknowledged that technical challenges escalated proportionally with increasing water depth.

The technical bottlenecks posed by deepwater and ultra-deepwater environments were multidimensional and interrelated. Among them, the most critical constraint was identified as the “narrow formation pressure operating window.” Shallow formations in deepwater settings were often under-compacted. They exhibited low mechanical strength. This resulted in an extremely narrow safety margin between formation pore pressure and fracture pressure. Conventional drilling practices relied on the hydrostatic pressure from a single-density drilling fluid column within a marine riser system. Precise and stable pressure control within this critical window was difficult to achieve. Consequently, fluid influx (kicks), losses, or wellbore collapse was frequently encountered. Secondly, the “physical and economic limits of traditional riser systems” presented a major challenge. In conventional offshore drilling, the riser served as the key piece of equipment for establishing a drilling fluid return path. However, as operational water depths increased, the corresponding increase in riser length introduced a series of derivative problems [1,2]. Conventional steel riser systems possessed significant weight. They required complex tensioning and compensation. Dynamic response issues related to their length were also noted. Therefore, a practical upper limit for their safe and economical operation existed [5]. The deployment of long risers led to high capital and operational costs. Furthermore, stringent demands were placed on the drilling vessel’s variable load capacity, deck space, and dynamic positioning system [1,2]. Additionally, during the initial “open-hole” drilling phase prior to riser installation, a standard “pump-and-dump” practice was often employed. Drilling mud and cuttings were discharged directly into the ocean. This practice was identified as causing significant marine environmental pollution. It also represented a substantial waste of valuable drilling fluid [6].

To systematically overcome these inherent limitations, a shift in technological paradigm was pursued by both industry and academia. Among the proposed innovations, Dual-Gradient Drilling (DGD) was introduced as an unconventional drilling technique. It was designed to control bottomhole pressure by altering the pressure gradient within the wellbore annulus. This objective was achieved through methods such as the utilization of subsea pumps or the modification of annular fluid density [7,8]. Consequently, DGD provided a theoretical framework for addressing the core challenges.

The Riserless Mud Recovery (RMR) system emerged as one of the most mature and commercially successful engineering implementations of the DGD concept. It effectively solved the problems associated with mud handling and recovery during the open-hole drilling phase. A closed-loop, recoverable drilling fluid circulation system was established without the use of a conventional riser [9,10,11]. Several key benefits were realized through this approach. Shallow geohazards, such as water flows, were mitigated. The marine environment was better protected. Furthermore, the wellbore architecture could be optimized. This optimization often resulted in a reduction in required casing strings. Therefore, major challenges in deepwater drilling were addressed [12,13,14,15]. As a result, RMR technology has been established as a key and widely utilized technology in deepwater oil and gas drilling. This is particularly true for challenging shallow hole sections.

To ensure the comprehensiveness and reproducibility of this review, a systematic literature search was conducted. The following electronic databases were searched: Web of Science, Scopus, OnePetro, and Google Scholar. These databases were selected to cover both peer-reviewed journals and conference proceedings. To capture recent industry developments and patented technologies not always published in journals, the Derwent Innovations Index was also consulted. Additionally, authoritative industry reports from organizations such as IHS Markit and Westwood Energy were screened.

The search timeframe was set from January 1990 to December 2025. This period was chosen to encompass the entire technological evolution, from the conceptual germination of DGD to the latest deepwater applications of RMR technology. The primary search string used was: (“Riserless Mud Recovery” OR “RMR” OR “Dual Gradient Drilling” OR “Subsea Mudlift”) AND (“deepwater” OR “top hole”). Relevant combinations of these terms were also applied.

The initial search yielded over 100 documents. A two-step screening process was then implemented. First, titles and abstracts were reviewed to exclude records not pertinent to RMR or DGD. Second, during the full-text assessment, we specifically excluded technical manuals and promotional materials authored solely by vendors that lacked original technical data or failure analysis. Following this rigorous process, approximately 60 references were ultimately selected for this review. The final reference set includes journal articles, dissertations, conference papers, patents, and technical reports, ensuring a representative and academically rigorous sample for analysis.

2. The DGD System: From Principles to Historical Evolution

2.1. Core Principles of DGD

DGD was defined by the International Association of Drilling Contractors (IADC) as “the use of two or more pressure gradients within selected sections of the wellbore to manage the pressure profile” [16]. In essence, the single, linear hydrostatic pressure gradient from the bottom of the well to the sea surface, characteristic of conventional drilling, was replaced. It was substituted by a segmented, multi-gradient structure. This structure was better matched to complex formation pressure profiles.

Compared to conventional riser or riserless drilling, the DGD configuration establishes a pressure control node at the seabed. From the surface to this node, the annulus is filled with seawater or low-density fluid, forming the first low-gradient segment; from this node to the well bottom, the annulus circulates weighted drilling mud, creating a second steeper gradient. The physical effect is equivalent to “virtually” placing the hydrostatic reference point of the drilling platform at the seabed, thereby significantly reducing the excess hydrostatic head acting on the open hole section. This mechanism effectively widens the drilling window [17]. By eliminating the hydrostatic pressure of a long column of drilling mud, the bottomhole pressure can be more precisely controlled within the narrow safety margin between pore pressure and fracture pressure [18].

2.2. Historical Evolution of DGD Technology

The history of DGD technology is a history of innovation. It was closely intertwined with the demands of deepwater oil and gas exploration. Technical and economic bottlenecks were continuously overcome. The development trajectory clearly illustrates the entire process. This process spanned from conceptual germination and technical verification to commercialization exploration and application domain expansion. Several cycles of “dormancy and revival” were experienced. Ultimately, maturity and diversified application were achieved. This achievement was driven by the push from industry giants and the pull of cross-domain demand.

2.2.1. Conceptual Germination and Early Shelving (1960s)

The technical idea of DGD can be traced back to the 1960s. At that time, the concept was initially proposed in the form of “riserless drilling”. Its core idea was to simplify offshore drilling operations by removing the heavy riser system [19]. This forward-looking concept aimed to address the simplicity issues of early offshore operations. However, its realization was severely limited. Key technologies were lacking. These included subsea pumping technology, subsea control systems, precise pressure management, and high-performance drilling fluid systems. Consequently, an engineering foundation for implementation was absent. Furthermore, the global focus of oil and gas exploration remained primarily onshore and in shallow waters during that period. Demand for technologies capable of handling extreme conditions was not yet apparent. Such conditions included ultra-deep water and narrow pressure windows. Economic driving force was weak. Therefore, after its proposal, this forward-looking concept failed to progress into a substantive research and development phase. It was quickly shelved and remained merely a theoretical proposition [19].

2.2.2. Conceptual Germination and Early Shelving (1990s)

In the 1990s, the global energy landscape shifted. Simultaneously, exploration technology made significant strides. These factors combined to reignite opportunities for DGD development. Exploration technologies advanced considerably. Major deepwater oil and gas fields, including those in the Gulf of Mexico, were subsequently discovered. This success shifted the energy industry’s focus to deepwater and ultra-deepwater regions. However, these deepwater environments also introduced unprecedented technical challenges. First, as water depth increased, the weight of conventional riser systems grew exponentially, placing extreme demands on the variable load capacity and positioning systems of drilling platforms. Second, shallow subsea formations were often unconsolidated or fragile, posing geological risks such as shallow water flows and gas hydrates. Deepwater formations presented a critical challenge: a very narrow pressure window. Conventional drilling was prone to fluid loss or kicks. Consequently, operational risks and costs increased substantially [9].

The distinctive feature of this period was that the Joint Industry Project (JIP) became the predominant model for tackling technical challenges. Research evolved from piecemeal efforts into organized programs. The year 1996 marked a crucial turning point. A landmark workshop was organized under the leadership of ConocoPhillips and Hydril. This workshop brought together approximately 25 major operators, contractors, and service companies to jointly assess the potential and development pathways for DGD technology [8]. A direct outcome of this meeting was the establishment of the “Subsea Mudlift Drilling (SMD) JIP”. The mission of this JIP was clearly defined: to pool industry resources to advance DGD technology toward commercial viability [8]. In the same year, industry enthusiasm for DGD surged, leading to the launch of multiple parallel research and development initiatives. Projects led by companies such as Shell, Deep Vision, and Maurer Technology (which focused on hollow glass sphere buoyancy solutions) were initiated. This created an initial developmental landscape characterized by vibrancy, collaboration, and competition, which fully underscored the significant importance accorded to this technology by the industry [8].

2.2.3. Technology Verification and Initial Commercialization Hurdles (Early 2000s)

After nearly five years of concentrated efforts, the SMD JIP achieved a substantial breakthrough in the early 21st century. In 2001, the project team successfully drilled the world’s first proof-of-concept well for the dual-gradient principle. The operation was conducted at Texaco’s “Shasta Prospect” well site in Green Canyon Block 136 of the Gulf of Mexico. The semi-submersible drilling rig New Era, operated by Diamond Offshore, was utilized for this operation in a water depth of approximately 277 m [8]. This field trial was of historical significance. For the first time, it verified the engineering feasibility of a complete DGD system—including the subsea pump module (SPM), control systems, and return lines—in an actual offshore environment. It demonstrated that the system could perform its designed functions while maintaining well control safety. This milestone marked the formal transition of DGD technology from the drawing board and laboratory to field practice [19]. During testing, some instrumentation problems arose. Additionally, the technology’s unpredictability called for more assessment. Nevertheless, the reported success rate reached as high as 90%. The outcomes were highly encouraging [19].

However, this technical feasibility did not translate immediately into broad commercial adoption. Despite the successful verification, the path to commercialization faced significant obstacles. The challenges were threefold. First, early DGD systems were highly complex. Second, retrofitting rigs was expensive—the SMD JIP alone cost about $45 million. Third, the oil and gas industry was hesitant to embrace unproven technology [20]. Retrofitting rigs for DGD was deemed too costly and risky. Oil prices were unstable, and returns uncertain. So despite early excitement, DGD failed to gain traction. It remained a technology admired but not adopted. Industry attention notably cooled in the subsequent years of the early 2000s, leading to a significant deceleration in its commercial rollout.

2.2.4. Strategic Involvement of Industry Giants and Diversified Development of Technological Pathways (2009 and Beyond)

Deepwater challenges have not diminished. They have grown more severe with increasing depths. A pivotal turning point came in 2009. Chevron Corporation made a strategic decision to re-evaluate DGD technology [21]. The goal was to enhance safety, predictability, and efficiency in deepwater operations. Chevron partnered with AGR SubSea, a specialized drilling services firm. Together, they designed, manufactured, and tested a new, more reliable DGD system. This marked a new phase: major operators with deep capital now drove the technology’s maturation. Chevron’s vision went further than joint research. To maximize DGD effectiveness and avoid costly rig retrofits, they took a bold step. They commissioned the world’s first DGD-specific drillship [21]. Built by Pacific Drilling in South Korea, the “Pacific Santa Ana” featured advanced capabilities: a water depth of 12,000 ft and a drilling depth of over 35,000 ft. The vessel was delivered in 2011. Its mission: drill in the Gulf of Mexico, including the world’s first commercial SMD well. The industry saw this as transformative. Chevron’s move signaled deep confidence in DGD. It prompted the entire sector to reconsider deepwater approaches. Supply chain confidence surged [21].

Meanwhile, the DGD technology ecosystem exhibited a trend toward diversified development. Various technological pathways emerged and evolved competitively, enriching the technical essence and application scenarios of DGD. One example is Ocean Riser’s Low Riser Return System (LRRS). It achieves a dual gradient by adjusting the riser mud level and using SPM for returns. The design bears similarities to AGR’s approaches [22,23]. AGR, meanwhile, continued to innovate. It launched its EC-Drill system in 2013. The system was successfully deployed on the Scarabeo-9 rig in the Gulf of Mexico. Industry experts consider this one of the first genuine commercial successes for DGD technology [23,24].

2.2.5. Expansion of Application Domain: From the Oil and Gas Industry to Scientific Ocean Drilling

The development trajectory of DGD technology has not been confined to the commercial oil and gas sector. Its unique technical value has attracted significant interest from the scientific drilling community. The IODP and its predecessors have long faced a critical technical bottleneck: how to conduct deep coring (e.g., in subduction zones or deep into oceanic crust) in hyper-deepwater environments (exceeding 4000 m). Within the existing fleet, Japan’s drillship Chikyu, while equipped with a riser enabling deep drilling and pressure control, has a limited maximum operating water depth. The U.S. drillship JOIDES Resolution, capable of operating in most of the world’s ultra-deepwater areas (2500 m), employs a standard riserless drilling mode using only seawater as the drilling fluid. This results in shallow penetration depths, low core recovery rates, and minimal capacity to cope with formation pressure anomalies, severely constraining both scientific objectives and operational safety [17].

DGD technology is aptly regarded as an ideal solution to bridge this “ultra-deepwater, deep-drilling” technological gap. It enables scientists to achieve closed-loop fluid circulation, precise downhole pressure management, greater drilling depth, and improved core quality in ultra-deep water without the need for a heavy riser system. This opens access to previously unreachable deep-sea geological, biological, and climatic records. DGD technology has gained strategic recognition from IODP for future scientific drilling [17]. Developed initially by the energy industry, DGD now aligns with scientific exploration needs. This industry–science collaboration creates new application opportunities and drives further technological advancement in reliability, long-term performance, and extreme environment operations. In summary, the evolution of DGD technology is a classic innovation case characterized by “demand pull, technology push, and tortuous progress.” It originated as an advanced concept in the 1960s, only to be shelved due to insufficient technological readiness and market demand. Revived in the 1990s to address deepwater challenges, DGD technology was validated through a JIP. After a period of commercial stagnation in the early 2000s, it achieved commercial success through strategic leadership and investment from major operators like Chevron, including the commissioning of purpose-built drillships. This breakthrough also spurred the development of diversified technical pathways. More profoundly, due to its fundamental capability to address deepwater pressure control, the technology’s value has transcended its original oil and gas industry scope. It is now emerging as a key enabling technology for advancing frontier Earth science exploration—particularly ultra-deepwater scientific drilling. Evolving from an industry tool into a versatile deep-sea engineering solution, DGD technology is poised to contribute significantly to both energy security and scientific exploration.

3. RMR System Architecture, Workflow, and Historical Evolution

RMR technology is an innovative drilling solution. It was originally developed by AGR of Norway, later renamed Enhanced Drilling. The system is based on the company’s Cuttings Transport System [25,26]. The RMR system is a mature and commercially successful realization of the DGD concept. It is specifically engineered for challenging top-hole sections in deepwater and ultra-deepwater environments. Its primary objective is to establish a closed-loop circulation system for drilling fluid. This system returns fluid from the wellbore to the rig, all without using a conventional riser. This is achieved through a sophisticated subsea architecture and precise control mechanisms. RMR effectively resolves key issues in conventional open-hole (or “pump and dump”) drilling. These include environmental pollution and significant fluid loss. It also mitigates risks from shallow geohazards. Furthermore, it provides unprecedented capabilities for wellbore pressure management [9,10,11].

The original impetus for RMR was to solve two main problems in marine top-hole drilling. First, it aimed to eliminate the environmental impact and high costs of discharging mud directly into the sea. Second, it sought to address high well control risks and poor borehole quality. These risks occur when drilling through shallow gas, shallow water flows, or weak formations. In such zones, conventional methods prevent the use of performance-tailored, weighted drilling fluids [14]. The following sections briefly describe the RMR system’s architecture and its operational workflow.

3.1. System Architecture

The RMR system is a complex engineered system integrating subsea mechanical components, fluid transport, power supply, and real-time control. Its main components can be categorized into the subsea module, the surface support system, and the umbilical cable and return lines connecting the two, all working in concert to achieve enclosed lifting and circulation of drilling fluid. The subsea module includes the Suction Module (SMO) and the SPM. The connection and transport system comprises the Mud Return Line (MRL) and the Power & Signal Umbilical. The surface support and control system consists of the Power & Variable Frequency Drive Unit, the Main Control System, among others.

3.1.1. Subsea Module

The subsea module forms the core of the RMR system that interfaces directly with the wellhead. Installed on the seabed, it is primarily responsible for collecting the returning fluids and channeling them into the lifting system.

SMO: The SMO is typically installed above a low-pressure wellhead structure (e.g., a guide base) and serves as the starting point of the entire system. It is a critical subsea vessel whose main function is to receive drilling fluid, cuttings, and formation fluid returning from the wellbore annulus [27]. Its design has evolved from an early “closed” configuration with a rotating control head to the currently widely adopted “open” design. The open design allows seawater to enter freely from its top, forming a distinct interface with the drilling fluid inside the SMO. This interface is crucial because by precisely controlling its height (i.e., the height of the drilling fluid column inside the SMO), the hydrostatic pressure acting on the bottom of the well can be regulated, providing the basis for initial pressure control [28]. The SMO is equipped with high-resolution cameras and pressure sensors for real-time monitoring of the fluid-level interface and internal pressure, with data transmitted in real time to the surface control room [29].

SPM: This constitutes the “heart” of the system, providing the power required to lift the drilling-fluid mixture from the seabed to the drillship located several kilometers above. The RMR system typically employs specialty pumps designed for harsh operating conditions, such as disk-friction pumps. This type of pump utilizes the frictional effect between high-speed rotating disks and the fluid to achieve pumping and exhibits high tolerance to fluids containing abrasive cuttings [30]. The SPM is connected to the bottom of the SMO via a flexible suction hose and is itself stabilized on the seabed by an anchoring system or a suspension arrangement. The pump speed (rotational speed) can be precisely regulated from the surface and serves as the primary actuator for controlling the return flow rate of the drilling fluid.

3.1.2. Connection and Transport System

This part acts as the “bridge” connecting the seabed and the surface, establishing channels for material and information transmission.

MRL: This is a high-strength, flexible or semi-rigid line extending from the outlet of the SPM to the drillship. It is responsible for safely conveying the lifted mixture of drilling fluid and cuttings back to the deck. The MRL must withstand the internal fluid pressure, the external hydrostatic pressure of the deep-water environment, as well as dynamic loads induced by currents and vessel motion. To prevent collisions or interference with the wellhead or drill string, its lower end is secured to the seabed via a dedicated anchoring system. This design primarily restricts horizontal movement while allowing a degree of vertical flexibility to accommodate sea-state conditions [27].

Power and Signal Umbilical: The umbilical serves as the “nerves and veins” of the system, integrating power cables and signal-transmission fiber-optic/electrical cables. It supplies power to the subsea mud pump, sensors, and cameras within the SMO while transmitting real-time data (pressure, temperature, fluid-level images, etc.) collected by the subsea sensors and pump status information to the surface control unit. It also relays surface control commands to the subsea actuators such as the pump.

3.1.3. Surface Support and Control System

The surface system is deployed on the drillship, providing power, control, processing, and analysis for the entire RMR operation.

Power and Variable-Frequency Drive Unit: This unit supplies and distributes electrical power to the entire RMR system, particularly to the high-power subsea mud pump. It includes variable-frequency drives that enable precise control of the SPM motor speed, thereby allowing stepless, fine adjustment of the pumping rate. This is key to dynamically responding to downhole conditions and maintaining stable system operation [30].

Main Control System: This is the “brain” of the RMR system, typically located in the driller’s cabin or a dedicated control room. The control system integrates all necessary hardware and software, receiving a continuous data stream from the subsea sensors and displaying it on an operator console. Operators can monitor in real time critical parameters such as SMO fluid level, pump pressure, pump speed, and return-line pressure. Based on these data and control algorithms, the system can automatically, or the operator can manually, adjust the SPM speed to maintain a set SMO fluid level, thereby achieving management of the bottom-hole pressure. A well-designed control system ensures efficient communication and coordinated operations between the driller and the RMR operator.

Handling and Storage Equipment: This includes a dedicated umbilical winch for deployment and retrieval, as well as reels or a deployment frame for handling the MRL. These devices ensure that subsea components can be safely and efficiently deployed and recovered.

3.2. Workflow and Pressure Control Principle

The workflow of the RMR system is a dynamic, closed-loop circulation process, the core of which lies in actively managing bottom-hole pressure by controlling the drilling fluid level inside the SMO.

3.2.1. System Start-Up and Circulation Establishment

After drilling the conductor section and before commencing the surface hole section, the RMR operation sequence is initiated. First, the SMO is lowered and installed onto the wellhead. Subsequently, the suction hose between the SMO and the SPM is connected, and the pump module is positioned suitably on the seabed. Next, the MRL is deployed, with its lower end connected to the pump module outlet and its upper end routed into the drilling vessel’s mud processing system. The power umbilical is simultaneously deployed and connected to the pump module. After completing all connections and testing communication and functionality, the subsea mud pump is started. Drilling fluid is pumped from the rig pumps down the drill string to the bottom of the hole, carrying cuttings back up the annulus into the SMO. The pump module continuously lifts the mixture from the SMO back to the vessel via the MRL. The returned mud is processed through solids-control equipment such as shale shakers and desanders to remove cuttings; the cleaned drilling fluid is then directed to the mud tanks, ready to be pumped downhole again, thereby forming a complete, closed circulation loop under riserless conditions.

3.2.2. Core Mechanism of Pressure Control: SMO Level Management

The key to RMR’s bottom-hole pressure control lies in the precise management of the height of the drilling-fluid/seawater interface inside the SMO. In conventional open-hole (pump-and-dump) drilling, bottom-hole pressure is determined solely by the seawater hydrostatic head. In the RMR system, the hydrostatic pressure acting on the bottom of the well consists of two components: the pressure from the column of drilling fluid from the bottom of the hole to the SMO inlet, and the pressure from the fluid column from the SMO inlet to sea level. The latter depends on the fluid level inside the SMO: if the SMO is full (high fluid level), this part is a drilling-fluid column; if the SMO level is drawn down by pumping, the upper portion is filled with seawater.

The control system regulates this fluid level by adjusting the flow rate of the SPM. The control logic is to indirectly maintain a stable bottom-hole pressure by keeping the drilling-fluid level inside the SMO stable at a preset “set point.” Specifically:

Increased Returns from Downhole: If a formation fluid influx or increased rate of penetration causes a momentary increase in flow entering the SMO, the SMO level tends to rise. Level sensors detect this change, and the control system immediately commands the SPM to increase its speed, raising the flow rate to pump more fluid back to the vessel, thereby pulling the level back to the set point and preventing a decrease in bottom-hole pressure.

Decreased Returns from Downhole: If lost circulation occurs or the rate of penetration slows, reducing the flow into the SMO, the level tends to drop. The control system then commands the pump to reduce its speed, decreasing the flow rate to prevent the level from falling too low and allowing excessive seawater entry, thus avoiding a sudden increase in bottom-hole pressure.

Through this dynamic balancing, the RMR system can stabilize bottom-hole pressure within a more optimized and controllable range than that provided by a seawater column alone, all while operating without a riser. This is particularly beneficial for mitigating geohazards such as shallow water flows and shallow gas, as the effective circulating density can be increased by appropriately raising the SMO fluid level to suppress high-pressure zones [31].

3.3. RMR Technology: Evolution, Industry Impact, and Future Prospects

Since its first commercial application in 2003 at the West Guli field in the Caspian Sea (15 wells), RMR technology has rapidly demonstrated its core value in achieving “zero discharge” and enhancing operational safety. Early systems utilized a flexible return hose and were capable of operating in water depths up to approximately 549 m [26].

In 2010, the system achieved another significant milestone. This occurred while drilling the 26-inch top-hole section of the Krakatoa well in the Mississippi Canyon, Gulf of Mexico. The operation encountered abnormal pore pressure at just 400 m below the mudline. By using a performance-optimized drilling fluid and ensuring its effective recovery, RMR enabled the section to be drilled successfully. This accomplished an operational objective that conventional riserless drilling could not achieve [31].

This field application did more than prove RMR’s exceptional capability in managing complex shallow geological conditions. It also established a crucial technical foundation for the system’s evolution into deeper waters and more demanding operational environments.

The industry’s move toward deepwater and ultra-deepwater exploration exposed key bottlenecks in shallow-water RMR systems: insufficient pumping capacity, limited flowline structural integrity, and poor deep-sea environmental adaptability. To extend the technological advantages of RMR to broader maritime domains, AGR collaborated with industry leaders such as Shell, BP America, and Norway’s DEMO 2000 research program to launch a strategic JIP aimed at co-developing a deepwater version of the RMR system [27]. The development of deepwater RMR was not a mere scale-up but involved a comprehensive reinforcement and redesign of key subsystems tailored to the unique challenges of the deepwater environment:

Revolutionary Enhancement of the Pumping System: The head and power of a single shallow-water pump proved inadequate for demands at depths exceeding one thousand meters. Deepwater RMR innovatively introduced a tandem SPM system. Typically, one pump is installed near the seabed, while another is positioned at an intermediate water depth. This multi-stage lifting configuration functions as a “relay station” for drilling fluid returns, significantly enhancing the system’s capability to reliably lift dense, solids-laden drilling fluid from extreme depths to the platform. This constitutes the foundational basis for the feasibility of deepwater operations [27,32].

Structural Innovation of the MRL: Flexible hoses were prone to insufficient strength and deformation under high deepwater pressure. Deepwater RMR decisively upgraded the return line material to high-strength connected steel casing. This steel pipe offers superior resistance to compression, tension, and fatigue, enabling it to withstand the immense hydrostatic pressure, internal fluid loads, and potential current impacts in deepwater, thereby ensuring the structural integrity of the return pathway in harsh deep-sea conditions [27].

System Integration and Intelligent Control: The deepwater system integrated more advanced auxiliary functions, including specialized casing attachments for suppressing Vortex-Induced Vibration (VIV), an enhanced anchoring system to improve seabed equipment stability, and high-precision multiphase flow meters and volume monitoring systems. These improvements enhanced the overall system stability in dynamic marine environments and strengthened the monitoring and response capabilities to downhole complexities, such as gas influx [33].

In 2004, the improved prototype system completed its first deepwater trial in the North Sea. A key milestone was achieved in late 2008, when the system was field-tested on a deepwater semi-submersible in the South China Sea at 1419 m water depth—a record at the time. The successful trial not only confirmed deepwater RMR technical feasibility but also demonstrated additional advantages: enhanced wellbore cleaning, deeper casing running capability, improved cementing, and elimination of fluid supply and waste disposal bottlenecks typical of conventional deepwater drilling [27]. This success marked the official strategic transition of RMR technology from a “specialized tool for shallow water” to a “mature deepwater drilling solution,” paving the way for its broad application in global deepwater basins. Subsequently, its deepwater operational capability has been consistently validated. For instance, in 2015, Enhanced Drilling performed what was then the deepest RMR operation (at 890 m water depth) on the Norwegian Continental Shelf for a major operator and secured a four-year service contract, demonstrating its technical leadership and reliability in deepwater environments.

Following its deepwater validation in 2008, RMR technology did not plateau but entered a phase of rapid development characterized by continuous refinement, integration of innovations, and expansion of application boundaries.

3.3.1. Continuous Iteration of Return Line Configuration

The return line, as the system’s “main artery,” has undergone technological evolution that directly reflects the relentless pursuit of reliability and adaptability in engineering practice.

Phase I (Shallow-Water Period): The system primarily relied on large-diameter flexible hoses, which offered the advantage of rapid deployment but were sensitive to water depth and pressure.

Phase II (Deepwater Breakthrough Period): The adoption of all-steel drill pipe/casing as the return line, coupled with tandem pumps, enabled a solid transition into deepwater operations [27].

Phase III (Hybrid Optimization Period): To further balance strength and flexibility, companies like Enhanced Drilling introduced a hybrid configuration featuring a “steel riser (upper section) + flexible jumper/hose (lower section).” This design employs rigid steel pipes in the upper section to withstand the primary environmental loads while using flexible elements in the lower section or at the platform connection to absorb platform motions (such as heave and surge). Its successful application at 854 m water depth in 2016 marked a significant step towards expanding into more complex sea states and deeper waters [34].

Forward-Looking Direction: For future hyper-deepwater (>3000 m) and harsh environment applications, the concept of Hybrid Riser Systems from traditional oil and gas production is being integrated into RMR design optimization. This solution decouples the system from the platform via a static rigid riser column and a top flexible jumper, which can significantly mitigate fatigue damage to the return line caused by dynamic platform motions. This represents a key technological direction for enhancing the reliability and longevity of ultra-deepwater operational systems [35,36].

3.3.2. Deep Integration and Convergence with Advanced Drilling Technologies

The controlled closed-loop circulation and pressure management capabilities provided by RMR make it an ideal “enabling platform” for the safe application of other radical or precision drilling technologies.

Synergy with Drilling-with-Casing (DWC) Technology: On the Northwest Shelf of Australia in the Dampier Sub-basin, to address the severe stick–slip vibrations and sticking risks caused by hard–soft interbedded layers in the “Bare Sands” formation, the operator pioneered the combination of RMR with DWC technology. The greater torsional stiffness of the casing string effectively suppressed vibrations, while RMR ensured efficient hole cleaning and pressure control within the narrow annular clearance. This culminated in a world-record single-run of 1710 m drilled at the time, demonstrating the formidable power of “aggressive technology combinations” in solving specific drilling challenges [37].

Deep Integration with Managed Pressure Cementing (MPC) and Controlled Mud Level (CML): In challenging areas like the Barents Sea, characterized by narrow drilling windows and frequent shallow geohazards, operators innovatively integrated the RMR system with MPC/CML technologies. By modifying the adapter of the RMR SMO to establish a closed-loop system, precise dynamic control over the subsea wellhead pressure was achieved during the surface hole section. This maintained annular pressure balance throughout cement slurry displacement and curing, preventing formation losses or fluid influx. Following riser installation, CML technology was further utilized to adjust the fluid column height inside the riser, optimizing the downhole pressure profile. This integrated approach addressed complex operations such as casing, liner cementing, and well abandonment in challenging scenarios like deeply fractured carbonate reservoirs. This integrated system, combining the efficient recovery and circulation of weighted drilling fluid via RMR with the fine-tuned pressure management of MPC/CML, significantly enhanced cementing quality and wellbore integrity. It has been successfully implemented in multiple field applications to avoid non-productive time, providing a key technical paradigm and reliability benchmark for deepwater drilling in harsh environments [28,38].

3.3.3. Expansion into Extreme Environmental Protection and Novel Fields

The “zero discharge” characteristic of RMR has enabled it to play a unique role in ecological protection. At the Zumba exploration well in the Norwegian Sea, to safeguard the dense and precious cold-water coral colonies surrounding the well site, RMR was innovatively employed for the entire well section, including conductor drilling. Coupled with the fully enclosed recovery and onshore treatment of cuttings, this achieved genuine “zero discharge of cuttings to the sea.” Although costs increased significantly, it established a new technological benchmark for responsible resource exploration in extremely ecologically sensitive areas [39].

Furthermore, the potential of RMR technology has attracted attention from the scientific community. The IODP collaborated with industry to explore the adaptation of the RMR system for use on the scientific drillship JOIDES Resolution. The goal was to enable scientific drilling in hyper-deep water (target depth of 3657 m) without relying on a large, expensive conventional riser system, showcasing its broad prospects for application beyond the oil and gas sector [17].

In recent years, the intensive commercial deployment of RMR technology in the North Sea region has been particularly noteworthy, highlighting its critical role in supporting the dual strategies of regional energy supply and emission reduction targets.

In March 2022, the international energy company Repsol signed a multi-well contract with Enhanced Drilling to deploy its RMR system at the Yme field in the North Sea. The system addressed top-hole section stability issues by utilizing weighted drilling mud and real-time monitoring while completely enclosing and recovering all drilling fluid. This supported the field’s transition from a decommissioned asset to a producing project while significantly reducing environmental impact and operational costs [40]. Shortly thereafter, in May 2022, China National Offshore Oil Corporation also applied the technology in its Golden Eagle development project in the North Sea. By establishing a closed mud circulation system, the project achieved zero emissions during drilling and enabled real-time monitoring of wellhead flow changes for prompt identification of losses or kicks. This contributed to the North Sea region’s goals of emission reduction by 2030 and achieving net-zero emissions by 2050 [41]. In June 2022, Enhanced Drilling secured multiple RMR service contracts from three major operators consecutively in the UK North Sea, marking a strong resurgence of its business. The technology, by establishing a closed mud circulation system for the recovery and reuse of drilling fluid and cuttings, not only reduced material consumption and greenhouse gas emissions but also optimized well architecture by reducing the number of top-hole casing strings. Recognized as a ‘Best Available Technique’, it supports the UK Continental Shelf’s transition towards a net-zero emissions target by 2050 while maintaining oil and gas production [42]. These concentrated commercial contracts demonstrate that RMR has evolved from an innovative technology into a standardized solution for meeting stringent environmental regulations and reducing total operational costs.

4. Technological Limitations and Future Improvement Directions

4.1. Limitations and Field Challenges of RMR Technology

RMR technology was first commercially applied by AGR in 2003 at the West Azeri field, Caspian Sea. Since then, it has been deployed in over 1000 wells worldwide [43].

Table 1. Global Application Statistics of RMR Technology and Corresponding Challenge Mitigation.

Region/Basin	Representative Application Scale	Primary Geological/Engineering Challenges Addressed	Key Benefits and References
Caspian Sea	Early commercial application (15 wells), cumulative >52 wells	Validating feasibility, operations in environmentally sensitive areas	Drilling fluid recovery, reduced cost and environmental impact [26,28]
North Sea	Widespread application, 73 wells	Shallow gas, narrow drilling window, improving efficiency	Early wellbore control safety, optimized well architecture [44]
Australia	Browse Basin & Dampier Sub-basin, 29 wells	Shallow water flows in unconsolidated sands, severe vibrations in “Bare Sands” formation	Enabling stable drilling, world record with DWC [37,45]
Russian Far East	Sakhalin Island & Barents Sea, 7 wells	Harsh environments, zero discharge requirement, weak formation pressure management	Environmental compliance, efficient pressure control [29,38]
Gulf of Mexico	Multiple deepwater blocks	Complex shallow geohazards (shallow water flows, shallow gas, reactive clays)	Deep surface casing running, minute-level early kick detection [46,47]
Brazil	Santos Basin, etc.	Wellbore stability in extended-reach wells, formation erosion	Pressure window management using dual-gradient technology [48]
West Africa/Gulf of Guinea	Deepwater development projects	Deepwater narrow drilling window, shallow flow risks	Reliable dual-gradient drilling solution
Southeast Asia	Offshore Sabah, Malaysia (e.g., Malikai field)	Safe deepwater surface casing installation, high-quality cementing	Improved cementing conditions, wellhead stability [49]
Norwegian Sea	Multiple wells (e.g., Zumba well)	Extreme environmental requirements (coral protection), shallow water flows	“Zero discharge” for entire section, ecosystem protection [39,50]

summarizes these global applications and the primary challenges each region addressed. However, increasing water depths and harsher operating environments have revealed significant technological limitations. These limitations are evident in its economic performance, equipment reliability, and operational scope.

It is noted that some field cases cited in this section were sourced from industry conference papers and service company technical reports. RMR technology was developed primarily through collaboration between service companies and operators. Therefore, early application data predominantly came from such channels. To ensure objectivity, this section incorporates validation studies from independent academic institutions wherever possible. Industry reports are cited with a critical awareness of their potential perspective limitations. The technical limitations discussed below were derived from direct field feedback and engineering mechanism analyses validated by independent academic research.

4.1.1. Economic Aspects

The initial investment and operational costs of RMR technology present significant constraints. DGD theoretically reduces costs by minimizing casing strings. However, the SMD JIP field test at Green Canyon 136 in the Gulf of Mexico did not quantify initial investment and maintenance needs. This applied to high-cost equipment such as subsea pumps and drill string valves [8]. The project’s commercial failure was attributed to several factors. The economic downturn occurred as the project concluded. Rig modification and equipment procurement costs were prohibitively high. No operator possessed a sufficiently large deepwater portfolio. Such financial commitment was therefore unsustainable [21].

For Tullow Oil’s Zumba exploration well in the Norwegian Sea (2015), the total cost including the RMR system and ISO tank cuttings handling system was approximately $6 million. RMR system-related rig online time accounted for 2.9 days [39]. In 2009, Statoil applied RMR technology to the Krakatoa well in the Gulf of Mexico. The operation was conducted from the Discoverer Americas drillship. Compared to conventional dynamic kill drilling, RMR reduced drilling fluid consumption by 70%. It also decreased hole enlargement by 40%. However, the system’s initial investment and operational costs were not quantified [47]. Most drilling rigs lack sufficient power capacity to drive RMR systems. Additional diesel generators are often required, which further occupies deck space and increases costs [14]. Elvary Neftegaz conducted operations offshore Sakhalin Island. The company provided no quantitative analysis of system costs. Initial investment, installation, and maintenance expenses were not disclosed [29]. Wang (2022) [34] proposed a “subsea pump + gas lift” combined system. The scheme aims to reduce subsea pump power demand through gas lift assistance. However, this concept remains at the simulation stage. It has not yet been validated through field testing.

The economic breakeven point between RMR and conventional managed pressure drilling is not a fixed water depth. It is a complex function of geological conditions, logistics, and environmental requirements. In areas with shallow geohazards, logistical difficulties, or zero-discharge requirements, the risk-adjusted cost of RMR is significantly lower than that of conventional methods. For example, operations offshore Sakhalin saved 9 days of rig time by eliminating pilot holes. The Krakatoa well in the Gulf of Mexico reduced mud consumption by 70% [29,47]. Conversely, in mature shallow-water blocks with wide pressure windows and low environmental requirements, conventional drilling may be more economical.

Independent economic analysis frameworks indicate that RMR’s value proposition is highly sensitive to water depth, rig day rates, and shallow geohazard probability. Decision tree risk analysis of the Tidepole East-1 well demonstrated that RMR’s economic justification is not based on a fixed water depth threshold. Instead, it depends on probability-weighted costs of failures such as stuck pipe [37]. In mature shallow-water blocks with well-understood geology and wide pressure windows, conventional drilling is often more economical. However, in regions with shallow geohazards, logistical challenges, or zero-discharge mandates, RMR’s risk-adjusted cost is significantly lower than that of conventional alternatives.

4.1.2. Equipment Reliability and System Failures

Multiple equipment failures have occurred in field applications, severely impacting operational continuity.

Regarding pipeline systems, Elvary Neftegaz applied RMR to the Vasukanskaya-1 and Savitskaya-1 exploration wells offshore Sakhalin Island in 2006. Generator fuel line blockage caused subsea pump shutdown, which subsequently led to return line blockage by sand and cuttings. Under strong current conditions, the return line became entangled and kinked, disrupting operational continuity [29]. During Statoil’s operation at the Krakatoa well in the Gulf of Mexico, a severe gumbo attack occurred. The flexible steel suction hose connected the SMO to the subsea pump module. This hose collapsed due to a sharp increase in suction pressure. An ROV was required to replace the hose section. To clear gumbo from the SMO, approximately 8000 barrels of inhibitive water-based mud were discharged to the seabed [47].

Regarding seals and connectors, Lundin applied RMR/MPC technology in the Loppa High area of the Barents Sea. Surface casing cementing was performed on four wells. Several issues emerged during these operations. In Well 1, the low-pressure wellhead adapter seal element leaked during cement curing. Maintaining wellhead overpressure therefore became impossible. In Well 2, pressure peaks from cement wiper plug release exceeded the design rating of subsea hose connections. This caused seal rupture. In Well 3, 2.5 bar overpressure was successfully applied. However, 1.6 m³ of losses were observed. Consequently, the cement top remained 4.5 m below the wellhead [38].

Regarding operations and control systems, a field trial was conducted offshore Sabah, Malaysia in 2008. The Atwood Falcon drillship operated at 1419 m water depth. During deployment, 7–5/8 inch casing was run as the mud return line. Two umbilicals were also deployed simultaneously. Communication errors occurred between the driller and RMR operator. This caused premature shearing of the umbilical weak point. The subsea pump module had to be recovered and repaired. During drilling, more sandstone stringers were encountered than anticipated. This caused shaker screen blockage. Some untreated mud was consequently lost. After losses occurred in Zone 4, lost circulation material was pumped. Semi-solid material then appeared in the returns. This material was discharged from the top of the SMO to avoid shaker blockage. Variable-frequency drive cooling water high-temperature alarms caused early equipment shutdown [27]. Woodside Energy combined casing drilling with RMR at the Tidepole East-1 well in Australia. Drilling reached 1906 m depth. The drill shoe rupture disk then failed at 2500 psi differential pressure. This caused circulating pressure loss. The drilling section was therefore terminated prematurely [37]. At Tullow Oil’s Zumba well, drilling was interrupted for 15 h. ISO tanks onboard were full of cuttings. Bad weather prevented transfer to supply vessels. During pilot hole drilling, the flow rate was reduced to control downhole losses. This caused loss of real-time LWD data. The tool lacked memory mode. Consequently, data gaps occurred for certain intervals [39]. The 400 m-class RMR system was jointly developed by two institutions under the China Geological Survey. These were the Guangzhou Marine Geological Survey and the Institute of Exploration Techniques. Sea trials revealed several issues. The system had numerous components. Operational procedures were cumbersome. Level detection accuracy required improvement. Automatic control algorithms needed optimization [51].

Although RMR has been applied in over 1000 wells globally, detailed reliability statistics for subsea pumps operating beyond 1500 m are absent from the public literature. Such information remains commercially sensitive. However, cumulative well counts and continuous multi-regional applications indirectly demonstrate acceptable reliability levels. Furthermore, the failure modes documented above provide qualitative evidence for critical component improvement.

4.1.3. Application Range and Environmental Adaptability

RMR technology has clear water depth limitations and equipment adaptation requirements. The maximum operating water depth is 1400 m. Pre-surveys are required to determine optimal equipment placement on the rig. Modifications may be necessary, including deck reinforcement, nondestructive testing of welds, and umbilical winch dynamic load testing [14]. The deepest field-proven application is currently 1419 m [27]. The system’s design-rated water depth is 1524 m. Conceptual studies, such as hybrid riser configurations, aim to extend capability beyond 3000 m [52].

The connection method between the conventional RMR mud return line and the platform is a critical constraint on water depth extension. Traditional platforms lack heave compensation systems for the return line. This subjects connection points to repetitive impact loads from wave-induced platform heave motion. These loads significantly increase dynamic stress and affect system performance and structural reliability [52]. Beyond 1524 m water depth, the mud return line must be changed from a flexible hose to a steel pipe to meet strength requirements [17].

Furthermore, subsea current effects significantly constrain RMR technology extension to deep and ultra-deep waters. Independent academic research by the Norwegian University of Science and Technology rigorously analyzed fatigue failure mechanisms in marine risers under vortex-induced vibration [53]. The study was based on full-scale field measurement data from the 688 m long Helland-Hansen drilling riser. Gaussian mixture model clustering analysis was performed on 242 measured data sets. The research revealed the influence patterns of complex environmental load combinations on the dynamic response of slender marine structures. These combinations included current profiles, directionality, wave loads, and vessel motions. The study demonstrated that VIV response frequency is affected by multiple parameters. Current frequency-domain prediction methods are, on average, 30 times conservative in maximum fatigue damage assessment. This finding has significant implications for RMR mud return lines. As similar slender marine structures, MRLs face comparable fatigue damage risks from VIV. The research provided independent validation for engineering design of slender marine structures in strong current environments through combined experimental and numerical simulation methods. It corroborated previously reported field incidents of pipeline kinking under strong current conditions [29] and revealed the underlying mechanical mechanisms.

In this context, subsea pump power requirements increase by approximately 4.97 kW for every 100 m increase in water depth. Conventional closed-cycle riserless drilling systems relying solely on subsea pumps for mud lift face capacity limitations [34]. Wang (2022) [34] multiphase flow simulations indicated that at 1340 m water depth, fluid compressibility significantly affects pressure control response time. Increasing gas injection rates reduces pump load and alters system dynamic characteristics. Due to limited RMR system operational experience, equipment and procedural reliability have not been fully validated through field testing. Operating personnel also lack practical experience [8].

At the specific application level, RMR technology has been applied in China for pressure coring operations during marine gas hydrate exploration aboard drilling vessels. Its technical feasibility for top-hole drilling has been preliminarily validated. However, for commercial production testing phases, considering offshore operational risks, equipment maturity, and operational continuity requirements, RMR technology is more likely to find application in cost-reduction scenarios during later development stages. Currently, international application depths remain primarily limited to within 1500 m [54].

Additionally, when operating in LRRS heavy mode, the hydrostatic pressure of the mud column in the drill pipe during pump shutdown may cause formation fracture. This necessitates integration of a subsea choke valve in the choke line and addition of bypass lines. These requirements significantly increase system complexity and operational risk [23,34]. Compared to conventional surface managed pressure drilling systems, RMR pressure control accuracy in standard riserless configuration is limited by subsea sensor measurement precision and subsea pump response time. This inherent limitation further constrains its application potential in complex formations and narrow pressure window operations.

4.2. Improvement and Future Development Directions of RMR Technology

4.2.1. Equipment and Hardware Optimization

To address suction hose collapse, engineering design must optimize hose performance. This enhances collapse resistance during gumbo attacks [47]. For return line kinking in strong currents, bend restrictors should be installed [29]. To overcome water depth limitations, hybrid riser configurations represent a key direction. Buoyancy cans maintain constant top tension. This achieves mechanical decoupling from platform motion. It eliminates heave-induced vertical dynamic loads. The structure combines rigid vertical pipes with flexible jumpers. Numerical analysis defines optimal design parameters. Top tension ratio must exceed 1.5. Buoyancy can submersion depth should range from 150 to 250 m [52]. Wang (2022) [34] proposed a “subsea pump + gas lift” combined system. This scheme effectively reduces subsea pump power load. Optimizing gas injection parameters minimizes pump power while meeting cuttings transport requirements. System reliability is thereby improved. Regarding equipment sealing issues, low-pressure wellhead adapters require redesign. They must be pressure-tested after installation. Design ratings at equipment connections need improvement [38]. For power supply challenges, the solution involves dedicated generators. Detailed rig surveys and interface planning must be conducted in advance [14]. China’s domestically developed 400 m-class RMR system targets medium-term goals of 2000 m water depth. Its long-term objective reaches 4000 m. Continuous research focuses on mud lift systems, mud return riser systems, and deep-sea high-power transmission technology [51].

4.2.2. Operational Procedures and Well Control Technology Improvements

Specialized well control procedures must be developed. The LRRS well control procedure proposed by Falk (2011) [23] applies the constant drill pipe pressure principle. It regulates backpressure by adjusting a subsea choke valve. This achieves dynamic bottom hole pressure control without mud weight increases. Optimizing well control procedures through extensive simulation studies is essential. Improving drill string valve design and application is also critical. Conducting targeted training effectively enhances operator response capabilities [8]. Regarding conductor stability, the ELM-MIV weight analysis algorithm quantified influencing factor weights. Results showed that conductor wellhead height (48.73%), mudline depth (33.14%), and soil properties (8.62%) are the primary factors affecting conductor stability. This provides the quantitative basis for engineering design [55]. In cementing operations, managed pressure cementing technology precisely controls wellhead pressure using subsea pumps. Pressure can be trapped during cement curing to prevent fluid exchange between the formation and wellbore. After cement sets, pressure application verifies cement sheath integrity [28,43]. For low-flow-rate operating environments, LWD tools with memory mode should be selected. Inner string cementing techniques should be used for 20-inch casing cementing operations. This reduces cement discharge to the seabed [39]. As rig crews become more familiar with casing drilling operations, connection times are expected to further decrease [37]. Strengthening communication between the driller and RMR operator effectively prevents operational errors [27].

4.2.3. Application Expansion and Intelligent Development

RMR technology is expanding from shallow seas to extreme environments. These include ultra-deepwater and polar regions. The IODP is collaborating with AGR and other companies. They are researching RMR technology suitable for hyper-deepwater exceeding 3657 m [17]. Hybrid riser-based RMR systems provide a viable technical solution for deep-sea gas hydrate development. They offer superior water depth adaptability and full recovery capabilities [52]. To ensure new procedures are safe and efficient, project teams must conduct HAZOP reviews for all drilling and well control procedures. A job-specific training system should be developed. This includes exercises using DGD simulators. Practical training should be synchronized with equipment factory acceptance testing [21]. In China’s Shenhu Area of the South China Sea, gas hydrate drilling occurs at approximately 1200 m water depth. RMR can be directly applied for pressure coring aboard drilling vessels. However, lifting efficiency and equipment maneuverability require further enhancement [54].

Currently, research on RMR is transitioning from field application reports toward deeper mechanistic analysis and digitalization. Scholars utilize numerical simulations to study multiphase flow and heat transfer characteristics within the system [56]. They also investigate cuttings transport patterns [57] and analyze wave and current effects on pipeline dynamics [58]. Li (2023) [56] developed a transient heat transfer model. This model revealed the impact of thermal transients on drilling fluid rheology in deepwater RMR systems. It provides a theoretical basis for optimizing mud properties and pressure control. In the future, RMR technology will continue advancing toward several directions. These include adaptation to extreme environments such as ultra-deepwater and polar regions. Deep integration with automated drilling and digital technologies will proceed. Applications will expand into new fields including gas hydrate exploitation and deep-sea mineral exploration. RMR will thus maintain its position as a core technology for modern offshore drilling, particularly for complex and high-risk top-hole sections.

5. Conclusions

This review systematically traces the evolution of RMR technology. It covers the journey from its conceptual inception to its status as a key technology for top-hole drilling in deepwater and environmentally sensitive areas. It synthesizes over two decades of field experience and presents the following key findings:

Global Application and Effectiveness: RMR technology was first commercially applied in the Caspian Sea in 2003. Since then, it has been successfully deployed in over 1000 wells globally. Practice demonstrates its significant advantages. It mitigates shallow geohazards such as gas and water flows. It enables zero-discharge operations. It optimizes casing programs. It also improves wellbore stability, particularly in gumbo, loose sands, and narrow pressure window formations.

Technological Evolution: RMR systems have undergone three generations of hardware innovation. The first generation used flexible hoses for shallow water. The second generation employed steel return lines with tandem subsea pumps. The third generation features hybrid configurations combining rigid risers with flexible jumpers. This evolution has progressively extended operational water depth to a field-proven 1419 m. Conceptual design targets now reach beyond 3000 m.

Integrated Application Benefits: Integration of RMR with advanced technologies such as casing drilling, managed pressure cementing, and CML systems has yielded significant benefits. In geologically complex basins, this integration has achieved record-breaking drilling efficiency, high-quality cementing, and enhanced well integrity.

Independent Validation: Independent academic research, such as studies on full-scale riser vortex-induced vibration by the Norwegian University of Science and Technology, has validated fatigue damage mechanisms relevant to RMR return lines. This provides critical theoretical support for engineering design in strong current environments.

This study is constrained by the availability of publicly available data. A significant portion of field cases were sourced from industry conference papers and service company reports. While valuable, these sources may carry commercial bias. Reliability statistics for subsea pumps operating beyond a 1500 m water depth are absent from the open literature. Detailed cost–benefit analyses also remain unpublished. Such information is commercially sensitive. Furthermore, system failure analysis primarily relies on reported incidents. It does not draw from systematic failure databases.

To overcome current limitations and expand RMR capabilities, future efforts should focus on the following areas:

Hardware Optimization: Develop collapse-resistant suction hoses. Install bend restrictors. Adopt hybrid risers for mechanical decoupling. Introduce gas lift assistance to reduce pump power demand.

Procedural Improvements: Establish dedicated well control procedures. Quantify factors influencing conductor stability. Promote managed pressure cementing technologies. Enhance personnel training and communication.

Application Expansion: Extend to hyper-deep water (>3000 m) through collaborative projects such as IODP. Explore emerging applications including gas hydrate exploitation and deep-sea mining.

Digitalization and Mechanistic Research: Integrate transient multiphase flow and thermal models with real-time control systems. Utilize machine learning to optimize operational parameters. Predict system responses under complex environmental loads.

In summary, RMR technology has matured into a reliable and environmentally responsible drilling method. However, its continued progress depends on synergy between field practice and independent academic validation, as well as ongoing innovation in hardware, control algorithms, and cross-disciplinary collaboration.