Lost-Circulation Materials (LCMs) are used to control and mitigate fluid loss problems by fracture sealing. Without a proper lost-circulation technique, an increase in non-productive time (NPT) and well control problems may occur. A good design in the LCMs to seal fractures and to successfully prevent the occurrence of a serious lost-circulation event can alleviate a heavy drilling budget. Various LCMs exist in the market, of which can be broadly categorized as fibrous, flaky, or granular. Granular LCMs are effective in sealing fractures and are of low cost. A successful bridging and sealing from the LCMs depend on their mechanical strengths, shapes, sizes, and particularly, the particle size distribution (PSD). In this paper, the computational fluid dynamics (CFD) and the discrete element method (DEM) are coupled to simulate the sealing capabilities of granular LCMs on different PSDs. A single smoothed fracture is created for the study of such phenomenon. The dynamic process of fracture sealing involves the initiation of bridging from large particles and the effective particle packing to form a seal, thereby reducing the fluid loss. It is found that the LCMs with bimodally distributed sizes can achieve effective fracture sealing. The coarse LCMs should be close to the average fracture size, where accurate measurement is required. The median of the fine to coarse LCM sizes should not exceed 0.67 for fracture sealing to occur. The LCM blend consists of coarse and fine LCMs, where the fine to coarse LCMs by volume is around one third.

An operator and rig contractor implemented new drilling operation automation (DOA) on two rigs in North Dakota’s Bakken field. A set of DOA projects were selected to promote alignment and deliver valuable tools to improve operational performance based on a collaborative technology agreement to develop innovative DOA process solutions to reduce operational variation. The first sprint of project work focused on delivering a system that automatically carries out recurring drilling activities previously completed manually by a driller interfacing with drilling rig controls. Collaboration between the operator and rig contractor has been vital in developing technical workflows for automation that deliver value to all stakeholders. The operator and rig contractor developed, field tested, and proved the value of the implemented devices and systems. The project development process is described along with the methods used to overcome the challenges encountered during the first project sprint. Developing and deploying repetitive process automation has enabled greater control and driven operational consistency for repetitive drilling practices. The process will be shared to manage, design, and implement automated sequences to the field. The first project sprint delivered a valuable drilling system which executes automated drilling operations. This tool will act as a platform for the next stages of project work to improve management of a drilling automation plan and operations at the rig site. The results described in this paper were outlined as future steps in SPE 195818. The operator and rig contractor overcame some of the traditional cultural and technical barriers to efficiently develop DOA through technology collaboration. The project team used the operators’ standard well delivery processes to deliver a valuable tool to aid the driller’s workflow while standardizing repetitive and recurring steps in drilling operation activities. Engaging and collaborating with field personnel drove improvements to the automated processes and enhanced the value-adding tools to impact operations at a field level.

After a blowout incident, the wellhead conditions (hydrocarbon flow rate and pressure) are difficult to predict. The worst-case discharge during an offshore blowout has always been a concern for the oil and gas industry. When a blowout occurs, the two-phase flow establishes various flow patterns along the wellbore depending on several factors such as wellbore and reservoir conditions as well as flowing fluid properties. The multiphase (gas-liquid) fluid flows upward through the wellbore at an extremely high velocity that may reach a sonic condition at the wellhead. One of the challenges for the worst-case discharge rate calculation is predicting the pressure drop and velocity of the influx in subsonic and sonic conditions. This paper presents a novel computational tool which is developed to characterize the well control events by simulating the possible worst-case discharge (WCD) scenarios under field conditions. The exactness of a WCD prediction tool is strongly related to the accuracy of models used to analyze the two-phase flow and the formation of sonic flow condition. The WCD tool developed in this study utilizes the nodal analysis technique to precisely predict the wellhead conditions post blowout incident. The tool has two main parts: i) reservoir portion, and ii) wellbore portion. The tool integrates various reservoir, PVT and production models to estimate the deliverability of a reservoir. Different forms of hydrocarbon production (oil, dry gas, and condensate) from multiple reservoir layers are considered in tool development. To forecast pressure loss along the wellbore, well-established models have been selected to make predictions for different flow patterns (bubble, low-velocity slug, high-velocity slug, and annular flows). In addition, various two-phase flow models have been modified and adapted to suit the Worst-Case Discharge (WCD) predictions. Furthermore, based on experimental observations, a new flow pattern map has been established and implemented in the model. One of the findings of this study is that the WCD rate is not only dependent on conditions of the wellbore section but it is also influenced by the fluid properties and reservoir characteristics. Therefore, the tool accounts for reservoir type, the number of producing layers, formation type (consolidated and unconsolidated), fluid types (oil, gas water, and gas condensate), and the pay zone thickness. In addition, the tool allows the user to specify fluid and reservoir properties for each layer including permeability, water, oil and gas saturation, API gravity of oil, salt concentration, bubble point and reservoir pressure, irreducible water saturation, critical oil and gas saturation, and gas specific gravity. With respect to the wellbore section, the tool provides flexible options for the user to design the desired wellbore configuration. These options comprise of the depths of cased and open-hole sections, casing and hole diameter, the roughness of casing and open-hole section and the inclination angle of the wellbore. The tool provides good WCD rate predictions for wells with an inclination up to 45° from the vertical. This article presents a novel WCD tool developed based on modified mechanistic two-phase flow models, which are validated for wide ranges of gas and liquid superficial velocities. As outputs, the tool predicts the wellhead parameters post blowout incident such as WCD rate, gas and water rates, the occurrence of the sonic condition and surface pressure. In addition, it provides an inflow performance relationship (IPR curves) for each reservoir layer. Predicting the wellhead pressure at the moment of the blowout helps to control the well by determining the density of the killing fluid.

The drive for cost efficient solutions in drilling has become stronger the last few years, and one of the approaches to this end is to increase the level of automation. Automation is multi-disciplinary task, and to really succeed, there is a need for collaboration between the different parties in the drilling industry. In this paper we discuss which underlaying technologies within instrumentation, control systems and communication technology that should be in place for a typical model-based automation and well protection software to work optimal. We elaborate on what is needed to take out the full potential of performance-enhancing functionalities in automated drilling control software. We highlight the gaps present today and how this affects the automation efforts as a whole. The discussion shows that there are some low-hanging fruits that can give significant cost reduction and improvements in automation and safety, while there are also some technology gaps that will take some time to fill and that require coordinated efforts between the vendors.

More than 35 million m 3 of oil have been produced from the Mittelplate oilfield. Poor hole cleaning has been identified as a root cause for drilling problems in the horizontal sections of its ERD wells. Enhancing cutting removal in vertical wells, high-viscous pills are typically considered. However, literature is providing contradicting guidance of using sweep pills in deviated/horizontal wells. Thus, the purpose of this study is to provide an overview about the theoretical background on hole cleaning and to experimentally identify the best sweep pill for ERD wells. An apparatus has been designed as a closed flow-loop system consisting of coaxial pipes forming a horizontal well with a drill-string inside, two mud tanks, and a mud pump. Two pressure sensors are placed along the horizontal section, providing complementary information about the moving sweeping pill. Different pills (high-viscosity, medium-viscosity, high-density and a high-viscosity/high-density combination pill) have been circulated and the recovered model cutting material from one cycle of circulation has been re-weighted. To the best of our knowledge, it is the first time that such a fully scaled-down device including pressure sensors at the toe and heel of the horizontal section has been designed and used for the evaluation of sweep pills. It delivers an efficient and cost-effective method to optimize hole cleaning processes and prevent costly drilling incidents.

Exploration wells tend to produce challenging cement placement conditions with varying design elements to achieve the isolation requirements such as avoiding lost circulation and exhibiting high mud removal efficiencies. To satisfy both of these design elements, development of a cementing fluid (spacer) has paired multiple technologies helping overcome these requirements. The cementing fluid combines a lost circulation spacer, shown to be a cement placement aid, and a scrubbing or scouring additive, demonstrating support for high mud removal efficiencies. Thorough function-based assurance testing helped mitigate the identified deployment risks, due to their plugging natures, in combining these technologies. The paper will document applications where the cementing fluid helped achieve the isolation requirements when faced with wellbore instability during placement as well as the associated mud removal challenges from these limitations. The use of the cementing fluid may help others achieve success when faced with similar challenges.

Early detection and quantification of gas kicks during drilling and completions is essential to proper well control and in the prevention of blowouts. The utilization of distributed sensing techniques, acoustic (DAS) and temperature (DTS), enables real-time elucidation of these multiphase flow events. Identifying and validating event signatures (fingerprinting) in these sensing technologies is crucial to informing operators of how to interpret these data streams. Performing full-scale analysis allows these events to be properly characterized, given the complexities in the fluid mechanics and gas dynamics. This project utilizes a 9-5/8 inch and 5200 foot deep wellbore at the LSU PERTT Laboratory retrofit with distributed fiber optics (DAS and DTS) and 4 permanent pressure-temperature gauges to sense and visualize gas kick dynamics downhole in real time. Several experiments were performed involving the injection of nitrogen kicks through a chemical injection line and also by bullheading down 2-7/8 inch tubing in both stagnant and circulating water. Variations in flow rate, kick size, and backpressure are investigated including gas migration during shut-in. DTS and DAS data are collected downhole, along with gauge pressure and temperature at four depths along the wellbore. Data is consolidated with the rig recorded surface data to create a complete picture of the experiments. Several observations are possible with this new methodology. First, the gas kick is immediately visible (audible) entering the wellbore by the sensors and the gas front was traceable in real time as it rose to the surface, allowing for detection of a kick, improved estimation of kick size, and easy calculation of rise velocity. Second, the distribution of gas axially in the wellbore was visible and provided insights into the duration of the event. Third, the compressibility dynamics can be visualized with the DAS thus elucidating details of bubble and slugging sizes and dynamics and when discrete gas has completely circulated out of the wellbore. The frequency ban filtering of the data further augments the fidelity of gas bubble sizes and dynamics. These initial results provide a proof of concept for using downhole sensing for real time riser gas dynamic detection and characterization.

Ledong HPHT gas field in Yinggehai basin of South China Sea. The pore pressure ramp above the over-pressured target sand with narrow safe mud weight window lead to high drilling risk. To improve drilling safety, multiple steps and approaches were taken in real-time monitoring of pore pressure and target zone depth prediction. This paper will describe the different techniques applied in this field to optimize mud weight and accurate prediction of casing shoe position. Using real-time LWD and mud logging data, pore pressure was calculated and geomechanics model was updated while drilling. The geomechanics model was built and calibrated against drilling and surface data. Intermediate vertical seismic profile (VSP) data was used to correlate with surface seismic profile to predict top of over-pressured reservoir and pore pressure below the bit. Last year, the latest look-ahead technology based on LWD deep electromagnetic measurement was also used to improve the depth prediction accuracy and thin bed detection for high-pressured sands below seismic resolution. The real-time pore pressure monitoring keeps the mud weight and equivalent circulating density (ECD) within a safe margin to avoid kick and mud loss. The estimated pore pressure coefficient calculated in real-time was within 0.01 SG from actual measurement taken in permeable sandstone intervals. VSP data provides formation top prediction between 50 to 200m ahead of the bit in this area. Predicted depth accuracy varies but generally stay below 10m for the depth range mentioned above. The integration of LWD and intermediate VSP logging has helped to reduce the high depth uncertainty in the predrill model. However, the above technique could not resolve for thin beds or low acoustic impedance contrast formation. This advocate to the use of real-time high-resolution inversion bed boundary detection ranging from 3 to 20m below the bit. Clear prediction of resistivity profile ahead of bit enable proactive decision making while drilling. This additional information helped to improve depth prediction accuracy for casing shoe position and ensure well integrity.

This paper will discuss the Managed Pressure Directional Drilling fit-for-purpose solution deployed to meet the drilling challenges faced in 5 consecutive wells drilled in South Texas, USA. This innovative solution integrates a state-of-art Rotary Steerable System (RSS) with Managed Pressure Drilling (MPD) technology. Drilling hazards such as well control events, simultaneous kick-loss, and stuck pipe were mitigated, and an improved drilling performance with a reduction of NPT as compared to other directional drilling systems. The solution requires the integration of two highly technical disciplines, MPD and Directional Drilling. Hence, a Joint Operating & Reporting Procedure (JORP) and a defined communication protocol are crucial for effective execution. The solution is based on a rigorous Drilling Engineering process, including detailed offset wells analysis to deliver a comprehensive risk assessment & mitigation plan in collaboration with the Operator to tackle drilling hazards without compromising the directional drilling requirements. This paper will summarize the 5 wells operations, the drilling optimization results, and the lessons learned from an integrated services point of view in terms of deliverables that made the difference on this project and allowed the Operator to achieve their objectives. In particular, the effective communication protocol between the directional drilling services, MPD services, and rig contractors to ensure safe operational alignment.

Lost circulation (LC) is extremely costly to many drilling operations due to loss of mud and productive time. Significant industry resources have been devoted to providing recommendations for both preventing and curing losses. These comprise bridging particles, settable pills and a focus on the better understanding, measurement and control of downhole pressures. The industry has also started to examine the relationship between downhole losses and fracture geometry. However, there has been very limited verification and utilization of such effort. Knowledge of the loss mechanism(s), location of the thief zone and fracture geometry is fundamental for understanding and treating losses effectively. The proposed method introduces a systematic approach for diagnosing lost circulation into potential root cause(s) by utilizing up to twenty-two diagnostic indicators. This allows the most appropriate treatments to be mapped to the suspected root cause. This technique supports the creation of preventative strategies during well planning. For example, if induced fractures are identified as the most likely root cause in the planning stage, then a wellbore strengthening formulation based on the fracture width estimation is recommended. A proper treatment can be designed based on the fracture width analysis as the data becomes invaluable in determining optimum sealing and effective treatment for losses into conductive natural fractures/faults. In case of loss events, the fracture width can be estimated based upon loss rate, the mud rheology, bottom hole pressure and pore pressure. Field experiences demonstrate that natural and induced fractures are the two most common root causes of losses. For induced fractures, fracture width usually develops beyond 3000-micron (µm) once losses have occurred and the preventive lost circulation materials (LCM) have not then worked effectively. If the bottom hole pressures can be kept below fracture propagation limits (or far-field minimum horizontal stress), then induced fractures will not cause significant volume of losses. The drilling induced fractures can be modelled by using in-situ stresses, well trajectory, bottom hole pressure, geothermal and mud temperature information.

The Oil and Gas industry has historically relied on lagging indicators ( e.g ., number of spill events, volume of spill, number of well kicks, personal safety statistics) for measuring and monitoring safety performance. Even though these metrics provide some useful information on an organization's safety culture, they do not offer any predictive insights. Leading indicators are metrics for measuring and monitoring events that can lead to or contribute towards an incident. Well control incidents are low frequency-high consequence events. Carefully developed and tracked leading indicators can provide valuable information for preventing significant control events. Currently, a collaborative project is underway to engage the upstream oil and gas industry to develop leading indicators-based dashboard tools for predicting and thereby preventing well control incidents. The goal of this project is to develop a set of leading indicators-driven predictive tools with customizable dashboard displays, for multiple levels of decision makers, to constantly monitor and understand well operations risk from a process safety standpoint. This tool would provide the users (from frontline to management) with role-specific information from status of engineering barriers ( e.g ., hydrostatic head, BOP status and health) to organizational process safety elements ( e.g ., procedure, compliance, design, risk management). The ‘processed’ information presented in a dashboard setting can be considered as early warning signs of well control events, which should drive targeted corrective actions to minimize risks in well operations. The project has already identified significant work in this area both from academic and industrial sectors, which will help to build the foundation for moving forward towards building a robust and useful Leading Indicators Dashboard.

Wells in the Permian Basin continue to increase in technical complexity and lateral length, testing the limits of traditional completion practices in unconventional wells. Coiled tubing has been the standard method for drilling out frac plugs in the basin but has mechanical limitations in extended-reach and high-pressure laterals. Due to the increasing well complexity operators have begun using high technology hydraulic completion units (HCU), also known as a snubbing unit, to drill out frac plugs in certain Permian Basin wells. By using the HCU in wells with longer laterals, higher pressures, and downhole uncertainty/complexity some of the additional risk can be mitigated. The HCU system can provide a reliable and cost-effective means to cleanout laterals in the Permian Basin while reducing mechanical risk. The purpose of this paper is to present case histories that illustrate the positive impact of the HCU on field operations. This paper will also detail the evolution of the HCU over time to its current state of the art stand-alone rigless system.

An application for Pressurized Mud Cap Drilling (PMCD) was needed to successfully drill an U.S. onshore, unconventional, High Pressure / High Temperature (HP/HT) well. The length of the lateral, highly fractured formation & extremely high MWs needed to drill the lateral proved that conventional drilling methods would not be effective, so PMCD was utilized. The main challenge was to keep circulating pressures low while injecting the circulating fluid into the naturally highly pressurized formation. PMCD involves injecting / losing the circulating fluid (water) into the formation, in this situation, high formation fracture pressures required high surface injection pressures to push the fluid & cuttings into the formation. When the injection pressure was combined with the frictional losses through the drill string, anticipated surface pressures were over 10k psi when circulating. To combat the high circulating pressure, an approach was taken to use Friction Reducer (FR) in the circulating fluid, water, thus reducing the frictional pressure loss while circulating within manageable constraints. This paper will go into detail of the different phases taken to determine the appropriate type of FR based on lab testing, hydraulics model, temperature modeling, and the results from the application of the product in the drilled well. Extensive hydraulics modeling was conducted to determine the feasibility of using the FR and the final anticipated circulating pressure. The BHA and drill string design was optimized to maximize the least amount of pressure drop across the tools while staying within operating parameters. Concerns of the use of FR such as ECD effect, fluid flow characteristics for hole cleaning in the annulus, temperature effects of the water being pumped, and effects in the BHA were all considered in the engineering process. FR testing including, lab testing of the base fluid (water), differential scanning calorimeter to determine effects of BHT, FR shear testing, FR concentration percentage at various flow rates in a flow loop to calculate Reynolds number at the respective flow rates & concentration and differential pressure testing with time and temperatures. Based on the results from the hydraulics modeling and lab tests, an FR was selected and fully utilized in the application of the product. PMCD techniques with this FR was used and was fully successful in the intended reduction of the surface circulating pressures while drilling the well. Surface and downhole results captured the effects of the FR in the fluid system and data was collected and analyzed to show the expected vs actual results on various drilling parameters.

Two of the most important parameters to monitor during a primary cementing job are the flow rate in and return flow rate measurements. To achieve optimum quality control of a primary cementing job, measuring annular return rates and comparing them with simulated data in real-time will provide better understanding of job signatures and result in the best possible top-of-cement estimation prior to running any cement evaluation log or taking decision to continue drilling the next section of the well. The return rate job signature along with the wellhead pressure is essential to understand the behavior and discrepancies between simulated and acquired surface data. Therefore, to assess the risk of job issues, such as unsuspected washout and lost circulation among others, accurate measurements of the return rate are critical. Historically, cement job evaluation has been limited by the fact that most drilling rigs do not have an accurate flow meter installed on the annulus return line, and a simple verification of mud tanks volumes versus pumped volume, as reported by drillers or mud loggers, more than often results in an unreliable assessment of the volume lost downhole, due to the unfamiliarity with the U-tubing effect and lack of data consolidation from the cement unit (flow rate in) and the rig (flow rate in & flow rate out). This paper will review a solution developed to mitigate the lack of a direct flow rate measurement by computing and displaying the return rate using either a paddle meter measurement or the derivative over time of the volume observed in the rig tanks.

Wellbore construction practices are complex. Achieving dependable zonal isolation is a critical and challenging process to optimizing asset life and minimizing future well intervention. Sustained casing pressure challenges related to poor zonal isolation are well documented and can impact production that may require significant remedial well intervention. The need to address these challenges called for revisiting cementing operational practices and lead to the development of a Basis of Design (BoD) document as a tool to help manage well design practices and standards. As common industry practice to prevent fluid migration, slurry designs should be gas tight. To avoid unwanted wellbore fluids to migrate to surface, two things are required: less time to initiate migration and the lack of a flow path. With analysis of the current cement slurries, designs were unable to perform successfully on inflow tests due to low temperature of the zones to be cemented, increasing the transition time for a slurry to move from liquid state to solid phase. With extensive laboratory testing it was concluded that current designs were not addressing the bulk shrinkage phenomenon of cement, which could lead to the creation of micro annulus creating conduits for fluid migration. This paper will discuss the detailed analysis and testing of the current and new designs and techniques validated by laboratory tests and field executions (Cement Bond Logs) to prevent fluid migration and ensure that dependable long-term zonal isolation was delivered. Mud displacement mechanics needed to be optimized to reduce the risk of mud on the wall phenomenon. This included the design of spacers that increased the annulus mud displacement efficiency, improved standoff and finally optimum displacement rates to create sufficient annular velocity. A comprehensive look at all the pertinent steps in the construction of the well starting from the drilling phase, through cement job design, preparation and execution was required to ensure that the best practices are adopted to achieve the best results. Slurry selection, spacer formulation, centralization, hole cleaning and excess volumes were all at the center of the improvements that were necessary to achieve optimum results. A BoD document was developed as a roadmap for cementing to further enhance wellbore integrity. It formalized the planning, design and job execution practices and specified the slurry design, placement, and verification criteria for each casing section. Several cement jobs have been executed using the newly implemented practices that resulted in excellent zonal isolation results, which were verified through cement integrity logs. Since the implementation in all subsequent wells, no casing-casing annulus pressure issues have been reported.

Improper hole cleaning is a major cause of non-productive time (NPT) in drilling. Current hole cleaning practices are mostly based on experience, rules of thumb and simplistic calculations. Hence, they are not reliable and do not work as expected in all scenarios. There is the need for a robust, fast, and accurate approach to simulate cuttings transport, and provide reliable and useful estimations of the hole conditions in real-time. In this paper, a transient cuttings transport model is presented for real-time hole cleaning simulations. The model solves the transient conservation equations using a drift-flux modeling approach, which is applied to describe the multiphase flow of cuttings and fluid in the wellbore. The model uses experimentally derived equations that account for the effects of pump rate, pipe rotation, eccentricity, fluid rheology, inclination, etc. on cuttings transport. A fast numerical solver is used to enable real-time simulations, while providing numerical stability that is crucial to maintain the modeling convergence under area discontinuities. Using small time-steps, the model captures pressure wave behavior, which is necessary for simulating managed pressure drilling (MPD) operations. Pressure-dependent mud density, non-Newtonian viscosity, and cuttings slip velocity models are used to estimate downhole parameters such as pressure, cuttings concentration, bed height, drilling fluid and cuttings velocities, etc. The model can provide a drilling crew with accessible real-time simulation results on the rig for monitoring the hole cleaning operation and preventing problems from happening. Case studies are performed based on field experiments to analyze the effectiveness of the developed model on avoiding operational problems such as pack-off and stuck pipe. Results show that by monitoring the real-time cuttings concentration and bed height along the wellbore, the developed model can detect improper hole cleaning conditions and provide optimum drilling parameters to resolve problems, thereby minimizing NPT. The robust numerical scheme allows for simulations that are several times faster than the real-time operation on a standard desktop PC, providing the crew with enough time to take preventive actions. Clean-up cycles can also be simulated by the model to calculate and optimize the required parameters for optimum hole cleaning results. Required clean-up times are calculated for the field cases to ensure that cuttings are effectively removed from the wellbore before pulling out of hole and running casing. Moreover, MPD operations can be simulated using the model that consider the effects of cuttings concentration and bed blockage on the pressure profile. The developed model can provide valuable real-time information on downhole conditions to the drilling crew during the drilling process and give adequate time to the crew to take timely corrective action if necessary. Moreover, the model can simulate the planned drilling process and calculate optimum drilling parameters to avoid hole cleaning problems.

Maintaining well control is one of the most important considerations of any drilling operation, and early detection of formation fluid influx or mud losses is vital to safe drilling. Today's gain and loss detection tends to trigger too many false alarms; major improvements in reliability (few to no false alarms) and reactivity (no missed events) are needed without being user dependent. The new developed system optimizes both accuracy and efficiency. This system maintains a false alarm rate lower than current system, while detecting influxes or losses as low as 40 gal. It applies also to a wide variety of configuration: deepwater, managed pressure drilling, land rig operations, etc. This performance is achieved through a new flow-modeling processes combined with automated settings, real-time quality control and guided, intuitive software interfaces. From a purely user-dependent system, the new kick detection software is now based on automated processes, ensuring repeatable and optimal detection performances while minimizing risks of human error. The detection of abnormal flow conditions in the well relies on the comparison of predicted and measured flow at the exit of the well. The improvements of the flow modeling, such as new, calibrated pump-efficiency models based on the isothermal modeling of the pumps, increase the robustness and the reactivity of the detection system. The presented case studies allow quantifying improvements of the kick detection performance between the existing system and the new version, benchmarking both the influx-detection reactivity and the system reliability. Kick detection charts used in the study represent a new way of illustrating detection performances.

A blowout contingency plan was made for a gas field in a remote area with water depth exceeding 1600 m. The worst-case discharge analysis for a representative well in the field concluded that the reservoir is capable of producing at a highly prolific rate, which posed a challenge when developing a source control contingency plan that complies with governing regulators’ and operators’ internal requirements. Simulations using a transient multiphase flow simulator showed that the kill requirements could exceed the capability of a single conventional relief well; however, planning to intersect and coordinate a dynamic kill using multiple relief wells involved unacceptable operations risks. Furthermore, considering rig availability, limited pumping resources, and long mobilization times for this region, planning to use multiple relief wells is not a feasable option. A recently developed subsea flow spool system can eliminate the need for multiple relief wells in the case of potentially hard-to-kill blowouts, especially where a dynamic kill using multiple relief wells would involve unacceptable operations risks. Dynamic kill simulation shows that the subsea flow spool, coupled with a supporting mobile offshore drilling unit (MODU), flexible flow lines, a supplementary flow spool, and a casing string placed inside the riser will be able to achieve a successful kill if needed. Furthermore, detailed engineering analysis of triaxial loads, fatigue, and erosion were done for critical hardware components to ensure all potential failure points were addressed. In conclusion, the subsea flow spool is a key component of demonstrating a single-relief well contingency for potentially hard-to-kill blowouts

Pre-salt heterogeneous carbonate reservoirs typically present long net pays, high production/injection rates and some flow assurance risks. This paper presents general information, results and lessons learned regarding the installation of Intelligent Well Completion (IWC) in Santos Basin Pre-Salt Cluster (SBPSC) wells. It also presents some important improvements to be introduced in the future IWC systems specification and qualification based on the lessons learnt in these projects, setting some new challenges to the industry. The benefits expected with the use of IWC are achieved at the expense of challenging well engineering, since well completion design becomes more complex and well construction risks increase. Detailed and integrated planning is essential for the success of the operations, starting at the earliest phases of the well design and continued through detailed execution plans. The use of standardized practices and procedures has led to significant increases on installation performance. On the other hand, an open mind and a constant search for improvements allowed new solutions and procedures to be developed throughout the years. Regarding the system integration, a flexible and standardized control architecture was developed to allow combining different IWC providers and subsea vendors, which proved to be a successful approach. The most important improvement in IWC installation was the anticipation of the acid stimulation, nowadays performed before the vertical Wet Christmas Tree (WCT) installation. In order to achieve this goal some crucial improvements were gradually implemented in the stimulation practices, such as, an initial injectivity increase solution and some new acid diversion solutions, which allowed eliminating the use of coiled tubing and, as a consequence, the need of a subsea test tree. The well design team conducted an integrated risk assessment to properly evaluate the new practices and establish some actions to reduce the risks. Intense communication between production zones was observed during the acid job in some of the initial wells, ruining the gains of the IWC. After a comprehensive analysis, some possible causes were identified and with the new stimulation practices this issue was eliminated. Over the years, with the introduction of several improvements, some of them presented in this paper, the well completion duration was reduced to less than 50% of the one observed in the initial wells. This major performance increase has been essential to keep this deepwater projects feasible, especially in the oil scenario seen in recent years. Some of the new practices and lessons learned in this 100 wells equipped with IWC has set groundbreaking practices for Brazilian pre-salt fields development and may stand as a reference for the industry in similar deepwater projects. Additional requirements for future systems are expected to improve even further the performance in this scenario.

Effective well control depends on the drilling teams’ knowledge of wellbore flow dynamics and their ability to predict and control influx. Detection of a gas influx in an offshore environment is particularly challenging, and there are no existing datasets that have been verified and validated for gas kick migration at full scale annulus conditions. This study bridges this gap with the newly instrumented experimental well at PERTT (Petroleum Engineering Research & Technology Transfer Lab) at Louisiana State University (LSU) simulating an offshore marine riser environment with its larger than average annular space and mud circulation capability. The experimental setup instrumented with fiber optics and pressure/temperature gauges provides a physical model of the dynamic gas migration over large distances in full scale annular conditions. Current kick detection methods do not always reliably detect a gas influx and have not kept pace with the increasingly challenging offshore drilling conditions. Even though there have been some recent developments in offshore kick detection, all methods thus far are only qualitative in nature because they are based on measurements at the surface. This study addresses current kick detection limitations and illuminates the potential for implementing distributed fiber optic sensing (DFOS) to the marine riser as a non-invasive and effective kick detection method in both stagnant and circulating annular conditions. As North America's only academic full scale well testing center, an experimental well in the PERTT lab was utilized to monitor and characterize gas rise using DFOS to simulate well control scenarios in offshore drilling riser environments. DFOS allows for the tracking of the gas migration in both the stagnant and full-scale circulating annulus conditions. Data from pressure sensors is integrated with the distributed temperature (DTS) and acoustic (DAS) measurements, for real-time downhole monitoring of the dynamics of the gas migration and fluid front movement. By implementing time and frequency domain analysis of the fiber optic data, we show that the gas rise and water front movement can be identified. Both the water and gas injection down the tubing independently show characteristic fronts in the DTS and DAS data, which gives us confidence in our interpretation. Once the gas is present in the annulus, the DAS measurements indicate a higher than expected gas-rise velocity, and this is most probably due to the full-scale annular geometry and circulating conditions enabling a faster gas rise velocity compared to previous work in this area consisting only of small-scale experiments and experiments through tubing. The two-phase flow experiments conducted in this research provide critical insights for understanding the flow dynamics in offshore drilling riser conditions, and the results provide an indication of how quickly gas can migrate in a marine riser scenario warranting further investigation for the sake of effective well control.