In projects to develop offshore production in Brazilian pre-salt fields, an innovative model of subsea manifolds is being used, based on shared-actuation control (SAC) for the remote operation of valves. The control solution, which comprises the first full-electric robotic tool designed to operate in ultra-deep waters, has achieved an important mark in 2020, with the commissioning and start-of-operation of the first fabricated unit. In this article, we present lessons learned and discuss relevant specifications and programs of the technological development that contributed for the results obtained so far. Considering aspects on conception, technology, and environment of application, the pre-salt SAC required the adoption of new solutions on several disciplines of subsea engineering. As a typical case of technological development, the design process comprised decisions on engineering requirements and the establishment of a comprehensive qualification program. Now, after the first robot completing critical stages at field, such as subsea deployment, functional testing, and integration with the subsea system, we obtain a set of performance results that serve us to evaluate e.g. how effective were the selected technical specifications and testing routines, used throughout the engineering program. This discussion also provides possible adjustments in the overall development plan, considering its application as new generations of SAC arise. The commissioning in 2020 of the first robot resulted in its full integration with the subsea manifold and the correspondent production system, contributing to water-alternating-gas injection in the pre-salt field Tupi Extremo Sul. A second subsea system featuring the same model of robotic tool, for manifold control, is in advanced schedule in 2021 for integration in Búzios II, another pre-salt field in Brazil. Confirming the advantages that we could expect with the adoption of SAC in subsea equipment, the pre-salt SAC allowed a series of optimizations on design of the robot-controlled manifold. The robot tool replaced all the hydraulic actuators that traditional control systems, based on electric-hydraulic multiplexing, would require to implement remote controlling of the manifold valves. This led to a significant reduction on sizes and weight of the manifold structure.

Produced water is always an unwanted by-product for any hydrocarbon producing process. Underground disposal of the produced formation water has many benefits such as minimum or no damage to the environment. However, formation damage arising from injection of water containing impurities is usually of great concerns and poses challenges for maintaining good injectivity of disposal wells. Well stimulation is probably one of the most effective treatment to restore the injection of impaired wells. Therefore, well treatment and optimization always play an important role in cost saving and injectivity improvement. Although many treatments such as acidizing and mutual solvent have been developed as a standard practice and are widely employed in the oil and gas industry, there is no universal treatment recipe which may be used to effectively stimulate a well without doing any well specific studies. To effectively tackle the injection rate decline issue in water disposal wells, understanding the process, quality of injection water and the nature of the in-situ properties of the formation is vitally important. Therefore, analysis of the formation minerals and lithology, produced water, well performance and field stimulation histories had been thoroughly reviewed and examined to understand the root causes and the mechanisms underlying the rate reduction and how to improve the injectivity. Laboratory experiments had then been organized and conducted for evaluating and optimizing the treatment. Fit-for-purpose well treatments were finally designed and executed for field evaluation. Once the field treatment was done, a thorough review and benchmarking of the treatment job had been performed to capture the lessons learned. More laboratory evaluation may be necessarily carried out for further improvement in the next well treatment. Applying the above process to the treatment of water disposal wells, a new well specific matrix stimulation treatment had been developed and applied to a few water disposal wells over the last few years. When compared with the outcomes of other types of treatment in history, the injection gain from this type of treatment was significant with a maximum 400% injection increase. Moreover, the improved injectivity had longer effective duration up to 26 months so far. Still a few wells have no signs of injection rate drop. The benefits are obviously enormous in terms of cost saving and injection gain. Effectiveness of a well specific treatment is rooted into the thorough understanding of the physical and chemical interaction between alien fluids and the in-situ formation. Laboratory evaluation is an important key to the development of a successful treatment recipe, which was showcased by the work presented in this paper. This would enrich the expertise of petroleum professionals in the limited stimulation practice of the water disposal wells.

Control line integrity is fundamental to ensure operability of intelligent completion systems. Damage to control lines can normally occur during string deployment (by shock), or during productive life (by vibration-related fatigue). This work aimed to investigate how encapsulation will affect control line survivability throughout their entire life cycle. Numerical simulations were carried out using geometrical arrangements of control lines typically found in completion valves and tubings. For installation loads, lines were submitted to shock simulations, both inside and outside of protection clamps. The role of flatpack material was studied, as to which kind of material would better absorb impact energy. For productive life loads, the flow-induced vibration was taken into account for high-rate injector wells. Vibration loads were based on force results obtained by Computational Fluid Dynamics (CFD). Structural Finite Element Analysis (FEA) was performed to obtain local tensions to estimate productive life of lines.

Low salinity/engineered water injections (LSWI/EWI) have gained popularity as effective techniques for enhancing oil recovery. Surfactant flooding is also a well-established and commercially-available technique in the oil and gas industry. In this paper, a numerical 2D simulation model was developed to investigate the effect of hybrid surfactant-LSWI/EWI on oil recovery from carbonate cores under harsh conditions. The developed simulation model was validated by history-matching recently conducted surfactant corefloods in the secondary mode of injection. Oil recovery, pressure drop, and surfactant concentration data were utilized. The surfactant flooding model was then coupled with a geochemical model that captures different reactions during LSWI/EWI. The geochemical reactions considered include aqueous, dissolution/precipitation, and ion-exchange reactions. Different simulation scenarios were considered and compared including waterflooding, surfactant flooding, engineered water injection, hybrid surfactant-EWI, and hybrid surfactant-LSWI. Additionally, sensitivity analysis was performed on the hybrid surfactant-EWI process through capturing changes in surfactant injected concentration and adsorption. For the case of LSWI/EWI, wettability alteration was considered as the main mechanism underlying incremental oil recovery. However, both wettability alteration and interfacial tension reduction mechanisms were considered for surfactant flooding depending on the type of surfactant used. The results showed that the hybrid surfactant-EWI altered the wettability and achieved higher oil recovery than that of surfactant-LSWI and other techniques. This highlights the importance of selecting the right combinations of potential ions for a certain reservoir to maximize oil recovery rather than a simple water dilution. The results also highlight the importance of surfactant adsorption and surfactant concentration for the hybrid surfactant-EWI technique. This work provides insights into the application of hybrid surfactant-LSWI/EWI on oil recovery especially in carbonates. The novelty of this work is further expanded through comparing surfactant-LSWI with surfactant-EWI and understanding the controlling parameters of surfactant-EWI through sensitivity analysis.

Field A is located offshore of Peninsular Malaysia, consists of multi stacked reservoirs where previously the vertical communication between different units was considered to be well understood. Separate reservoir models were built independently where fair to good history matching were achieved during the dynamic modelling study. Subsequently two drilling campaigns were executed based on the simulation results. On top of that, regular reservoir surveillance and frequent simulation model updates have assisted in assessing vertical connectivity. North of Field A, a recent drilling campaign in early 2019 indicated possible communication between infill wells in Unit 35U and water injectors in Unit 35L. One of the well is experiencing severe watercut production than initially forecasted. It is well understood that the seismic amplitude for Unit 35L is being overlapped by the stronger response of Unit 35U in the northern area. Due to that, the reservoir modelling and understanding for Unit 35L in this region is mainly driven by actual well controls and the geological model, rather than from seismic. Meanwhile in the Southern area, a stable reservoir pressure trend is observed in Unit 27 despite reduction of cumulative voidage replacement ratio (VRR) from 0.6 to 0.4. Additionally well C02ST1 was producing oil at an increasing rate, a trend which the current reservoir model failed to match. The model also failed to explain the unreasonably high recovery factor (RF) of 50% for Unit 27 given the delayed water injection and small gas cap support. Back to the North, well interference testing was conducted by shutting in water injectors in Unit 35L and observing the pressure response of a new well in Unit 35U using a permanent downhole gauge (PDG). Observations indicated a decrease in pressure response once injection was turned off, confirming the communication between the two units. Moving forward, two injectors for Unit 35L will be temporarily suspended to relax the watercut trend in the new wells, thus improving the oil rate. In the South, a material balance study and reservoir 3D model suggest additional volume needs to be introduced for Unit 27, which indicates that it is probably draining Unit 35U oil due to a higher level of vertical communication and overlapping sand bodies between both units. This is also supported by produced water salinity readings of well C02ST1 (Unit 27) having similar values as Unit 35U wells rather than other Unit 27 wells. Communication between different layers often requires longer time and a significant amount of production to be well established and observed. This case study proves that reservoir understanding can still be a mystery even when the field is reaching 20 years of production.

Decommissioning of offshore assets in Brazil is subject to high level of uncertainty because of invasive Sun Coral Tubastraea sp. This species has an improved capacity of dispersion and recruitment, and has been associated with the replacement of native species in rocky shores causing severe impact to native biodiversity. Because of that, colonized artificial substrates will require cleaning and actions to avoid dispersion to the surroundings. This paper is proposing to study biology of Tubastraea sp, aiming to identify methods to eliminate and/or decrease its spreading. A colony of Tubastraea sp. was collected by scuba diving in Angra dos Reis (23o3.229'S / 44o19.058'W), Rio de Janeiro state, Brazil and transferred to a laboratory to proceed with a comprehensive analysis of morphology, cytogenetics, transcriptome, mitochondrial and nuclear genome. Colony morphology was analyzed and the skeleton was deposited in the zoological collection of the National Museum of Brazil (MNRJ 7129). Deoxyribonucleic acid (DNA) extractions were performed in clone polyps for the preparation of sequencing libraries. Bioinformatics was applied to assemble the first draft of the nuclear genome which was subsequently improved for contiguity using molecular and computational scaffolding methods. Our study showed the genome of Tubastraea sp is organized in 23 chromosome pairs and has 1.4 Gb making it the largest coral and Cnidaria genome sequenced to date. The hybrid assembly using short and long-reads has a N50 of 180,044 pb, 12,320 contigs and high completeness estimated as 91.6% of BUSCO complete genes. Results showed that almost half of the genome consists of repetitive elements, mostly interspersed repeats. Gene content was estimated as about 94,000, a high number that warrants deeper scrutiny. The Tubastraea sp. genome is a landmark study promising to provide insights not only about the genetic basis for the extreme invasiveness of this coral, but also to understand the adaptation flaws of some reef corals in the face of anthropic-induced environmental disturbances. We expect the data generated in this study will foster the development of efficient technologies corals species management, whether invasive or threatened. When oil&gas industry has a problem where conventional methods are not efficient enough, a multidisciplinary approach becomes necessary. This study consists in an innovative example of a partnership among high reputation biological entities and one operator was established to bring a broad understanding of an invasive species in Brazilian waters, extremely impactful to Decommissioning activities in country.

A major operator in the Norwegian continental shelf recently implemented an improvement program focused on increasing standardization and efficiency on subsea well operations. By including a Vertical Christmas Tree (VXT) rather than a Horizontal Christmas Tree (HXT) in their subsea completion design, several wells can be batch completed with a rig. VXT Installation can then be completed with an Installation, Maintenance, and Repair (IMR) vessel, eliminating the need for a Rig or Light Weight Intervention (LWI) vessel. In order to use an IMR vessel for VXT installation, a new method needed to be developed for the establishment/removal of a temporary second barrier between the well and subsea completion. The goal was to achieve a barrier valve solution that would be installed as part of the completion string. Furthermore, without requiring intervention via wireline or an LWI, it would accomplish three positional phases: open, closed, and then open again. The tool would be installed in the open position, allowing for all standard completion operations to be conducted. For example, lighter fluid could be pumped into the tubing prior to setting a packer, allowing for bull heading in a well control situation. By incorporating the valve into the completion string and ensuring the well design and operation is planned accordingly, wireline intervention can be entirely avoided The more common methods for suspension and initiation of subsea wells during BOP removal and VXT installation include installing shallow set bridge plugs in the tubing and/or a tubing hanger plug. The intervention plugs would then be removed using a riserless LWI vessel. This method is often associated with high cost and enhanced operational risk. A technology group was assembled in order to close the technical gaps inhibiting a fully intervention-free operation for completion installation. Technology personnel from both the operator and service company worked together closely to develop a glass plug solution that met all the necessary requirements needed to overcome this challenge while still minimizing associated risk. The proposed solution is a barrier valve to be integrated as part of the completion string; using glass plug technology, it will accomplish three positions: open, closed and then open again. The glass plug will first be installed with the bypass ports in open position, allowing for standard completion activities to be conducted. For example, an operator would still be able to accomplish bull heading in the event of a well control situation. The bypass is shifted to the closed position after a predefined number of tubing pressure cycles have acted on the glass plug system. Once the bypass is closed a ISO14310 V0Q1 well barrier is established. The glass plug barrier is only shattered after the tubing above the glass has been subjected to a predefined number of pressure cycles while applying a specific overbalance. After, the barrier element has shattered the valve it activates its final open state, resulting in full bore ID through the valve. This was developed and qualified according to ISO 14310 V0Q1 / ISO 28781 V1Q1 and installed in less than a year. By utilizing this glass plug the drilling rig can batch complete subsea wells and at a later stage batch install the VXT with an IMR vessel. The product can also be installed as part of conventional completion string were shallow barrier is required, eliminating the need of intervention. By implementing this technology, the operator saves time and cost addition to reduced HSE exposure associated with well intervention.

Implementing deep-offshore Enhanced/Improved Oil Recovery (EOR/IOR) is not an easy task. Bigger reservoirs, larger well spacings, injection/production/logistics constraints and difficulties to quantify benefits are some of the challenges that may be faced. This paper presents the status and future vision for the main offshore EOR/IOR research and field application initiatives of a brazilian Operator. Most promising technologies and issues will be described. Overall research structure, as well as adopted strategies to test and implement those techniques will be addressed. Difficulties eventually faced will be mentioned. The most promising methods in terms of water-compatible EOR are customized-composition waterflood, novel conformance control solutions and optimal reservoir management. Regarding gas-based technologies, the focus is on WAG flood, foam, subsea gas/liquid separation/reinjection and gas injection optimization.

At deepwater sites, skirted mudmats with a sliding mechanism have been the preferred choice to support pipeline or flowline end terminations (PLET or FLET) on soft clay seafloor to accommodate line expansions and contractions that occur during shutdown and restart cycles. The sliding mechanisms can experience line expansions of up to 4 m, or if it were to lock-up, horizontal forces in excess of 2,000 kN. The design and fabrication of sliding mechanisms for such large movements can often become challenging and costly. As an alternative, the industry is now designing mudmats that do not utilize sliding mechanism but rather slide directly on the seafloor, if necessary. While it is an attractive alternative and is gaining popularity, all aspects of direct sliding mudmat design are not sufficiently understood because of the complexity that arises from the interactions among the various components, i.e., flowline/pipeline, mudmat, jumpers, and the supporting soft seafloor behaving as one system. The design must ensure that the mudmat will not unduly sink, rotate or dig into the seafloor in the course of the back and forth sliding caused by many shutdown and startup cycles during the field's operating life. Therefore, it is essential to sufficiently understand the characteristics of the sliding motions and estimate as accurately as possible the resulting interaction forces in the flowline-mudmat-jumper-seabed system. This will allow the designer to avoid the risk of any system instability from incoherent component motions, or potential overstressing of connections. This paper investigates the direct sliding behavior of the mudmat motions using realistic simulations of the flowline-mudmat-jumper-seabed system. The simulations rely on coupled Eulerian (soft seabed) and Lagrangian (flowline, mudmat and jumpers) finite element analysis (FEA) method. The simulations yield insight into the complex mudmat sliding behavior interacting with the jumper, the hydrocarbon line and the supporting seafloor. The simulations show that merely modeling the mudmat alone fails to capture the actual behavior of a real-life PLET/FLET's back and forth cycling on the seafloor, because for example, the restraints (and attendant stresses) at the flowline and jumper connections are not accounted for, or that slanting the sides of the mudmat reduces its tendency to self-embed decreasing connection stresses. The paper demonstrates that realistic simulations allow important visualization of mudmat interactions with flowline, jumper, and the seabed during the shutdown-startup cycles, and provide accurate determination of the associated critical responses.

Long slugs arriving in separators/slug catchers is a major flow assurance concern in the offshore oil production industry, potentially causing flooding and/or severe separation problems. The sizing of the receiving facilities is determined by the longest slugs, so the economic implications of slug length predictions can be substantial. Slugs may also over time cause serious fatigue issues in free-span pipe sections, as large load variations can drastically reduce the lifetime of the flange connections. In most laboratory experiments reported in the literature, slugs rarely become longer than around 30-40 pipe diameters, while in many oil production fields, slugs can be considerably longer. Consequently, there is a clear need to better understand how and why such long slugs appear in production systems, and in this paper we present results that shed some light on this matter. We present a unique set of two- and three-phase slug flow experiments conducted in a 766 meter long 8" pipe at 45 bara pressure. The first half of the pipe was horizontal, while the second half was inclined by 0.5 degrees. A total of ten narrow-beam gamma densitometers were mounted on the pipe to study flow evolution, and in particular slug length development. In addition, the average phase fractions were measured using two traversing gamma densitometers, and one 160 meter long section with shut-in valves. The pressure drop was also measured along the loop using a total of twelve pressure transmitters. The results show that the mean slug length initially increases with the distance from the inlet, but this increase slows down and the mean slug length typically reaches a value between 20 and 50 diameters at the outlet. At low flow rates, the slug length distributions tend to be extremely wide, sometimes with standard deviations approaching 100%. The longest slugs that we observed were over 250 pipe diameters (50 meters). At higher flow rates, the slug length distributions are generally narrower. The effect of the water cut on the slug length distribution is significant, but complex, and it is difficult to establish any general trends regarding this relationship. Finally, it was observed that slug flow often requires a very long distance to develop. Specifically, in most of the slug flow experiments, the flow regime 50 meters downstream of the inlet was not slug flow. The reported experiments are the first three-phase slug flow experiments ever conducted in a large-scale setup. By using a long, heavily instrumented pipe, we were able to study the evolution of slug length distributions over a long distance. We believe that these experiments can be of considerable value for developing tools for predicting slug lengths in multiphase transport systems, which is a critical matter for oil field operators.

Boulders are known to be present within foundation zone depths at some Atlantic East Coast wind energy development areas, which can make it difficult to level a piled jacket or template and can lead to the progressive collapse of the pile toe, causing premature refusal during pile driving. Although detection and avoidance are preferred over mitigation, numerical analysis methods are available to assess the risk of pile refusal, which allows for informed decisions on whether avoidance is required and what types of mitigation to consider during construction. Detailed numerical evaluation (using one-dimensional wave equation analyses and two- and three-dimensional finite difference and finite element modeling) was performed to develop a better understanding of stresses in the pile during driving. The numerical modeling evaluated the effect of strength, thickness, inclination, shoe length, wall thickness, and lateral continuity on pile stresses. A three-dimensional model of the pile and driving shoe subjected to stress-time histories was used to evaluate the stresses at the pile toe and at the transition from the pile to the driving shoe. Example results are presented to illustrate failure mechanisms of hard layers that include boulders, and high-level guidance is provided on operational sequences and potential contingency measures.

Mass gravity flow phenomena resulting from mobilization of unstable sediments on submarine slopes are well recognized as a major geologic hazard for offshore infrastructure development. Previously published research pertaining to mass gravity flow impact on offshore infrastructure has focused on evaluating the direct impact loads generated by the flowing sediment mass in contact with the analyzed infrastructure component, such as a pipeline or a mudmat. In this study, the mass gravity flow impact on offshore infrastructure is addressed from a different perspective by investigating the potential for mass gravity flow induced seafloor scouring. Finite-element analysis is used to investigate the mobilization of near-seafloor sediments in a deepwater setting under the loads generated by a mass gravity flow event. Analysis results representative for a mass gravity flow in the far-field, near-field, and at the location of a mudmat supported subsea structure are presented and discussed in terms of failure mechanism, near-seafloor sediment deformation pattern and associated impact on stability of the subsea structure, in relation to flow thickness and position of the front of the flow relative to the subsea structure. For the case of a mass gravity flow in contact with the subsea structure, an example of failure envelope providing the ultimate lateral impact load from mass gravity flow required to cause instability of the structure, accounting for the flow induced mobilization of sediments underneath the mudmat, is also presented.

Plasma shock wave (PSW) has been proven to be able to destroy rocks and improve the ROP for conventional rotary drilling. The aim of this paper is quantify the damage caused by PSW generated by different discharge energies, and to study the mechanism and characteristics of PSW damage to rocks. The PSW has been extensively used in many areas, such as alternative fracturing. In the tests, the PSW reactor generated the electrohydraulic effect to convert electrical energy into mechanical energy, which was sufficient to destroy the hardest rock. Firstly, the experiment was carried out using concretes instead of real rocks. Secondly, three types of discharge energy were used to generate PSW to damage samples. Finally, the amplitude attenuation coefficient (AAC), the damage variable and the drillability were used to quantitatively analyze the damage of the samples. Experimental results showed that samples were impacted to produce many circular holes and cracks and the damage to samples increased as the energy increased. However, when the energy rose to a certain extent, there was a gradually decrease in the growth rate of damage. In addition, it was found that the AAC measured at different locations was different for the same sample, which indicated that the internal damage of a concrete sample produced by the PSW was anisotropic. Finally, the average drillability was improved after the sample was subjected to PSW impact. The findings gained will help understand the mechanism by which the PSW destroys rocks It also provide some methods to quantitatively evaluate damage of rock.

Technology gaps in measuring wellbore parameters and providing the results at surface without using wireline (Production Logging) or slick-line, without using mud-pulse, electromagnetic or acoustic telemetry, or pre-installed or permanently installed downhole sensors remain an area to be bridged. Our ability to engineer light-weight, high-strength, highly-reactive (dissolvable) or corrosion-resistant, nanostructured-alloys and intelligent micro-electromechanical system (MEMS) devices have enabled design of buoyant sensors having thin (millimetric) wall, capable of withstanding 20,000 psi or more differential pressure. These sensors measure and record a complete set of the client’s required wellbore parameters (e.g., Pressure, Temperature, Depth, Casing collars, Flow-rate across perforations or in wellbore, Water cut, Dissolved O2, etc.). These devices are deployed, either nested in an outer shell of salinity independent water reactive alloy to abet pump down to depth or weighed down by a sinker of dissolvable alloy. These devices are free-flowing within a wellbore so that they can be placed downhole to required depth for a specific time, after which the outer shell dissolves or the sinker weight falls, releasing the inner gauge. The now buoyant device flows back to surface with produced fluids where they make their presence known by sonic or inductive signaling. Our company was founded to take advantage of these disruptive innovations in materials science and sensors and synthesis of these technologies to provide superior performance products for both deep-water domains and the multistage stimulation (MSS) market. In this article we address two of our key inventions. First, the development of miniature, self-contained, battery powered, free-flowing sensor devices for reservoir monitoring, passively retrievable through carrier buoyancy. A subset of this game changing approach, to economize operations is, "Measuring in- situ pressure, temperature, and subsequent production during MSS". Second, we present a mechanism to assess susceptibility of oilfield alloys, especially in live reservoir fluids at the production zone. This encompasses a retrievable sensor device to assess environmental effects on materials at target zone in wellbore during production or shut in, can be deployed anywhere from production zone to bubble point, to surface separator. It facilitates testing not in a simulated autoclave environment at surface, but downhole, at the zone of interest.

Shallow water flow (SWF) is a common type of geological hazard in deep-water drilling. It usually occurs in a relatively shallow stratum below mud line (about 450-2500m). When encroached by a drill bit, the substantially over-pressured sand body can generate SWF that may dramatically impair the integrity of the drill string and the associated equipment. However, the mechanism that triggers SWF is lack of detailed understanding, leaving a safe design of drilling through SWF prone strata in suspense. In this paper, through the independent design and development of the shallow water flow simulation device, the damage, and flow mechanism of the sandstone occurred during the SWF events. It can be found through the experiment that in the occurrence of shallow water flow event, there is much sand accumulation around the pressure relief port. The sand body below the pressure relief port is lifted upwards as a whole, and the sand layer above the pressure relief port has a specific amplitude decrease. The findings could not only help understand the SWF process but also build a foundation for subsequent research on prevention and control of SWF incident. In addition, it provides theoretical guidance for improving drilling equipment to ensure that the SWF hazard is adequately controlled.

An offshore field has presented a challenging intermediate drilling application. The 2200-m section was drilled in a 17.5-in. hole to 3700-m true vertical depth. The lithogy of the section is variable, beginning with a soft claystone, followed by several sandstone formations, an 1100-m interbedded sandstone and claystone interval, a 125-m hard carbonate, and 50m of softer claystone before the casing point. The challenges presented in recent offset wells included high stick/slip, high levels of drill bit cutting structure wear and drill bit body erosion. Polycrystalline diamond compact (PDC) bit designs utilized in recent offsets varied from six to nine blades, with the interval requiring two or three bits to complete the interval. Based on results from other challenging offshore applications, including improved durability and drilling dynamics, the next-generation PDC and roller-cone hybrid drill bit (hybrid) with improved design features was selected for the application. Improved design features included a new increased blade count concept, combined with a sharp and dense roller-cone cutting structure. The application of the next-generation hybrid drill bit design delivered a reduction in drilling time and an improvement to drilling dynamics compared to offset wells drilled with conventional technology. Compared to the best offset well drilled in 17.5-in. hole a reduction in total drilling time of 59.4hrs (31%) was achieved. The reduction in drilling time resulted from both an increase in on bottom ROP of 32% and the removal a bit trip (19 hours) due to the interval being drilled in one run for the first time. Associated with the reduced drilling time, improvements in drilling dynamics were observed with stick/slip reduced by 73%. This paper illustrates the study of the application, applied learnings from new technology developments in hybrid technology evolution, and the subsequent improvements in drilling dynamics that resulted in improved penetration rates and cost savings in this challenging application.

Trip optimization is essential in multilateral well construction, especially for extended-reach drilling (ERD) wells. This paper describes the design, testing, and operation of a completion deflector running and test tool (RTT) that was recently used during completion of one of the industry's deepest extended-reach multilateral wells. The RTT allows for running and pressure testing of a completion deflector and lower completion components in a single trip, thus saving at least one trip, and up to three trips. The challenge was to develop the capability to run a completion deflector with an existing pressure test tool. This was accomplished by converting the pressure test tool into a running tool. The new pressure actuated mechanism built into the tool releases the completion deflector automatically after a successful pressure test. A secondary release mechanism was also incorporated for contingency options. Extensive engineering qualification tests validated the new features to be highly reliable.

Operators have, in the past, experienced high rates of corrosion for mooring systems in warm waters above those allowed for in traditional design guidance. The Joint Industry Project (JIP) for Seawater Corrosion of wire Rope and mooring Chain (SCORCH) was carried out with the participation of over twenty five offshore platform operators, equipment manufacturers, regulators and classification societies to address gaps in industry knowledge on the corrosion of steel wire rope and mooring chain, particularly in tropical waters. The five-year project involved a broad range of research from literature review through to field experiments, examination of recovered in-service components and derivation of generalised corrosion models. Coupons of several grades of chain were deployed for a two year period at a number of sites to account for variation in temperature, oxygenation, current/wave action and water quality. Full-size chain links and lengths of smaller chain were also deployed for comparison, with special laboratory tests to investigate the effect of nutrient content on microbiologically influenced corrosion (MIC). Wire rope tests were carried out for a similar variation of environmental conditions as the chain tests. A range of specimens including individual wire strands, and wire rope sections with varying levels of blocking compound, jacketing and galvanic protection were subject to exposure for a period of three years and 6 months. An extensive industry-wide survey of in-service and retired mooring components was also carried out to supplement these experiments. A standardised procedure for corrosion inspection was distributed to participants and a database of detailed wire rope and chain corrosion measurements was collated from approximately 30 floating production units (FPUs) operating in tropical waters in Asia, Africa and the Americas. Some recovered specimens were subject to more extensive examination, including 3D laser scanning and tensile break tests. The SCORCH JIP advanced knowledge in the field of mooring corrosion by providing guidance on inspection and integrity management methodologies, unique insight into the factors affecting the corrosion performance of steel wire rope and mooring chain, and generalised predictive corrosion models for the assessment of mooring corrosion. These recommendations are presented in the following paper.

Recently there has been significant interest in the development of seabed trenches associated with anchor chains in front of suction anchors. The issue was first highlighted by Bhattacharjee et al . (2014 ) in relation to the Serpentina FPSO located offshore Equatorial Guinea. The subsequent implications of the Serpentina experience have been significant, such that the geotechnical design of suction anchors now often includes allowance for the potential formation of an anchor chain trench extending down to the anchor padeye. Previous publications relating to anchor chain (mooring line) trenching have focussed primarily on observational case histories (e.g. Serpentina FPSO) and analysis of the impact of seabed trench formation on suction anchor in-place holding capacity. Furthermore, recent work by others outlined the results of 1g and centrifuge model anchor chain tests and the use of these results in the preliminary development of a chain model encompassing the progression of erosion and trench wall collapse with time. This paper describes a new design tool which permits identification of the primary mechanism leading to the formation of seabed trenches running along the embedded section of mooring lines in front of anchors. The model provides a direct approach to estimating the extent of seabed trench formation that may arise from mooring line motions under both normal (operational) and extreme (storm/cyclonic) conditions. As inputs the design tool requires the full mooring line layout/configuration from the fairlead (located at the floating facility) down to the anchor padeye, the range of design loads at any point along the mooring line and the seabed soil properties. Through an example study the paper demonstrates the ability of the design tool to back-analyse seabed mooring line trench formation at existing installations and predict the extent to which mooring line trenches may develop for new sites. The ability to perform site-specific assessments of trenching risk should in turn allow the industry to move away from including blanket allowances for trenches which, sometimes unnecessarily, mean that much larger anchors are planned than actually required.

The introduction of new technology is critical for operators to expand their completion options, increase efficiency, and drive profitably in challenging environments. For unconventional reservoirs, hydraulic fracturing in cased or open hole has been key for the economic success of new ventures. The continuous evolution in Completion technology has led to many advances in efficiency by the inclusion of degradable technologies. These technologies, when properly implemented, can reduce or even eliminate mechanical interventions, both during operations and post-stimulation. However, simply replacing current isolating technologies, balls or plugs, with one that will dissolve is not enough to capture the full value of these systems. Many operators have decided to experiment with degradable technologies without adjusting their current completion strategies. This approach can result in mixed success. For those operators who did not achieve the potential of the technology, a closer look is needed to decide if the degradable technology is compatible with the operator's drivers and overall strategy. A thorough review of current operating practices and environments is essential to understand how degradable technologies may be utilized to reduce cost, risk, and time associated with completion activities. In addition, the dissolution mechanisms must be understood to best decide how and when to use degradable devices. Environmental, procedural, and design considerations need to be evaluated to have a successful implementation of degradable technologies. These include: A) Environmental (e.g. reservoir pressure, BHST, etc.), B) Procedural (e.g. pump down fluid, stimulation fluid, etc.) and C) Design (e.g. tool design, degradation mechanism,etc.) This paper will provide a set of comprehensive recommendations to assist in job planning and execution. Examples will be drawn from various operating environments with their unique challenges discussed and analyzed. Following these recommendations, degradable technologies can more successfully be implemented and the reduction of costs, risks, and time associated with mechanical interventions can be achieved.