Casing-Running Analysis in Riserless Topholes

The basic principle of the Atlantis deep water drilling concept is to establish an Artificial Buoyant Seabed, the ABS, at a convenient water depth at which drilling can take place with a floating drilling installation using conventional subsea drilling equipment. The BOP and wellhead are located on the artificial buoyant seabed, which is placed at moderate water depth, 200 - 300 m. Anchoring of the ABS is achieved by extending the 20" surface casing from the subsea well. By moving the termination point of the well up to moderate water depth a number of problems and hazards normally associated with deep water drilling are reduced or eliminated. By applying sufficient net buoyancy to the ABS, the lateral offset and the bending moment of the surface casing string at mudline is kept within acceptable limits. The ABS can be compared to a submerged TLP and the tension applied to the casing string is well below the tensile strength of typical casing grades. The artificial buoyant seabed is an open steel structure, and buoyancy is provided by injection of compressed air. A main concern for all slender constructions in a sea current and wave regime are the potential vortex induced vibrations. The paper describes the analyses performed in this respect and why the concept is robust relative to this phenomenon. Many deep water well locations have very loose seabed conditions and foundation behavior becomes a problem. The pper soil layers can hardly provide the lateral support needed for the conductor. Contrary to the conventional use of a conductor, the foundation of Atlantis is based on the cemented surface casing and is therefore less dependent onthe soil strength in the upper layers. Actually, soft soil conditions become an advantage since it reduces the mudline moment. The casing - soil interaction was investigated and integrated in the casing string design, eliminating the need for both conductor and special stress joints. Instead of using buoyancy elements distributed along the riser combined with tension from the drilling vessel, the integrity of the casing string depends here on the adjustable tension provided by the ABS. A flexible and reliable ballast control system had to be designed. Introduction The Atlantis concept is a patented system for deep water drilling and field development. It was invented by Terje Magnussen, who is a senior consultant with Proffshore. Applications. The concept can be used in a range of applications from exploration drilling to field development. The exploration drilling version has a simple, single well ABS while the field development version uses a multi-well type and more advanced ABS. The concept enables the use of established FPU and FPSO technology also in deep waters. Drilling advantages. The operational and drilling related merits of the concept is not the main issue of the paper and is therefore described in Appendix 1. However, some key features are:deep water riser and BOP not needed;space and variable load capacity for long riser not needed;no time consuming deep water riser running and wellhead work runs;normal riser margin and improved well control;less possibility for formation of hydrates in the BOP

Summary Recent innovations in subsurface corrosion practices of the Arabian American Oil Co. (ARAMCO) have reduced logging and workover costs substantially and have permitted the detection of corrosion in the outer string of two concentric casing strings. At the request of ARAMCO, Schlumberger conducted test under both simulated and field conditions. Results showed that the data required to evaluate casing corrosion in a 7-in. × 9 5/8 -in. completion can be obtained during a single logging run using a 21.6-in. coil spacing electromagnetic thickness tool (ETT-A TM) sonde (as opposed to two runs with 17.6-in. and 21.6-in. sondes previously used). In addition, corrosion of the outer string of 9 5/8-in. or 13 3/8-in. casing can be detected by using the results of the ETT-A logs and pipe-analysis tool (PAT) logs or caliper logs. To date, the application of this technique has been very successful in ARAMCO's operations. Introduction For several years ARAMCO has used the ETT-A in conjunction with the multifingered caliper (MFC) tool for monitoring casing corrosion in single strings of both 7-in. and 9 5/8-in. casing. The results of these logs were often the basis for workover recommendations in injection wells and to a greater extent, when run in conjunction with workover operations on producing wells, the basis for additional operations to ensure good wellbore integrity. In the past, two separate logging runs were made to evaluate corrosion in each of the 7-in. and 9 5/8-in. casing strings. The 17.6-in. coil spacing ETT-A sonde was used in 7-in. casing while the 21.6-in. coil spacing ETT-A sonde was employed in 9 5/8-in. casing. The obvious disadvantage of this technique is the additional cost incurred in making two separate logging runs. An additional disadvantage is the added workover rig downtime. As corrosion in the near-surface outer string of dual casing strings increased, it became imperative to develop a technique by which corrosion in the outer string could be detected and corrected before complete breakdown of the casing resulted in underground communication or surface leaks. To this end ARAMCO approached Schlumberger to determine whether any of the corrosion monitoring tools (specifically the ETT-A) then in use could be adapted to detect corrosion in the outer string of two strings of pipe and to determine whether an optimal coil spacing existed that could be used in both 7-in. and 9 5/8-in. casing strings. Tests were undertaken by Schlumberger in their AlKhobar. Saudi Arabia, shops to determine the optimal coil spacing of the ETT-A and to confirm that this spacing could respond to the total metal of dual casing strings. Once this optimal spacing was determined, it would then be possible to use the ETT-A to check the total metal present, and when run in conjunction with the PAT or MFC, it would be possible to differentiate the corrosion affecting the inner and outer strings. JPT P. 801^

The conventional drilling approach of employing a drillstring and bottomhole assembly with bit for drilling purposes and eventually running a casing string includes several tripping operations that leave the wellbore open for extended periods of time as an alternative to drilling-with-casing operations where the bottomhole assembly is attached to the casing. This eliminates additional drillstring tripping as drilling and running casing are performed simultaneously. This type of application reduces the number of string trips needed to complete a section, thus saving operational time and associated costs. As the diameter of a casing is larger than a drillstring, this method generally increases the Equivalent Circulating Density (ECD) as pressure losses increase owing to the reduction of the open hole and casing string annulus area. Casing directional drilling operations provide a much narrower drilling window with regards to restrictions in the annulus thus increasing the chances of reaching fracture pressure compared with conventional drillstring operations. To negate the resultant increase in ECD, the rheological profile of the drilling fluid must be designed appropriately. This paper discusses a unique oil-based drilling fluid system weighted with treated micronized barite slurry (TMBS) that has more recently been developed and used successfully in the Eldfisk field of the Greater Ekofisk area, Norway. The drilling fluid system provides low viscosity and a relatively low flat rheology, reduced torque values, and superior sag stability, thus delivering a fluid of low ECD contribution, low-pressure peaks, very effective hydraulics performance and static stability. These exceptional fluid characteristics make the system an excellent solution for drilling sections where the difference between pore pressure and fracture pressure is narrow. This was particularly so in this case where the stability of the fluid from sag potential was crucial for the improved success of the drilling-with-casing operation. Any solids sag onto the latching tools or bottomhole assembly (BHA) with the casing could have caused interference. The system had been used before for differing hole conditions including managed-pressure drilling and extended-reach wells, in high-temperature, high-pressure (HTHP) wells, and now with competence in a casing directional drilling operation.

The application of surface blowout preventer (SBOP) drilling system in deepwater environments has been demonstrated that it can save operation cost and time. The high pressure small diameter casing plays the role of the conventional riser and bears the complex loading caused by the wave and current force and drilling platform motion. The coupled quasi-static and uncoupled dynamic analysis models of deepwater SBOP drilling system were established. The analysis results indicate that the uncoupled method without consider the lateral offset on the end of the high pressure riser nearly no affection to the riser analysis. However, the uncoupled method has a certain impact on the mechanical analysis of the subsea wellhead and the casing string under mudline. The lateral offset of the high pressure riser changes greatly in the different times, the bending moment of the upper and lower stress joint of riser is bigger. The platform long-term drift has a greater impact on the dynamic response analysis of the high pressure riser of SBOP system for deepwater drilling. DOI: http://dx.doi.org/10.11591/telkomnika.v10i4.858

The North Sea, in particular Norway, was a forerunner in regards to improved safety due to the mandatory introduction of mechanized systems for rig-floor operations. In the meantime also the offshore industry in the Gulf of Mexico has recognized the benefits of mechanized operations and now a large number of drilling rigs are equipped with equipment to remotely handle drillpipe, casing and tubing strings. The Total Recordable Incident Rate (T.R.I.R.) is the "measuring stick" of safety performance in the GOM industry. 1999 marked the beginning of an initiative to implement remote controlled, mechanized equipment wherever possible, in an effort to remove personnel from hazardous areas. The number of jobs that were run with mechanized equipment increased rapidly. At the same time the number of total recordable incidents was declining. An analysis of the percentage of jobs run with mechanized equipment versus the T.R.I.R. shows a remarkable and very obvious correlation. 1 Introduction The North Sea, in particular Norway, was a forerunner in regards to improved safety due to the mandatory introduction of mechanized systems for rig-floor operations. In the meantime also the offshore industry in the Gulf of Mexico has recognized the benefits of mechanized operations and now a large number of drilling rigs are equipped with equipment to remotely handle drillpipe, casing and tubing strings. The Total Recordable Incident Rate (T.R.I.R.) is the "measuring stick" of safety performance in the GOM industry. Mechanized and remote controlled equipment is used to make the environment on the rig floor safer, especially during drillpipe, casing and tubing handling and running. The analysis of the T.R.I.R. shows the typical incident rate before the mechanization was introduced, as well as the improvements in safety performance as the utilization of mechanized equipment increased. 2 Tubular Running Services Despite efforts to reduce the use of threaded connections, for example by the use of coiled tubing or the experimental use of welding or bonding technologies for running casing, running and making up of casing or tubing joints is still an important step in all drilling and completion operations. A typical well drilling operation requires approximately 30% of the total time for drillpipe tripping and casing and tubing running operations. 2.1 Traditional Tubular Running Services Traditionally, running casing and tubing strings required manpower and although hydraulic power equipment is used, a lot of the work has to be done manually (Fig. 1). The procedure of running pipe can be divided into handling tasks and tubular makeup. The typical equipment list for a traditional tubular running job already implies the manual work associated to it:thread protectorsdrifting mandrelshandling equipmentslip-type spiderslip-type elevatorsingle joint elevatorhydraulic power tong with free floating backupsingle-joint compensatorelectronic Joint Analyzed Makeup system The task of handling the pipe includesremoving thread protectors clean threadsvisually inspect threadslift pipe to v-doorengage single joint elevatorlift pipe into derrick

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18374, "Designing High-Angle, Casing-Directionally-Drilled Wells," by B. Borland, SPE, R. Watts, SPE, ConocoPhillips; B. Lesso, SPE, Schlumberger; and T. Warren, SPE, Tesco, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May. Copyright 2006 Offshore Technology Conference. Reproduced by permission. Casing-directional-drilling equipment and procedures for use on a mature North Sea asset were designed and tested. Testing this equipment in commercial North Sea operations is prohibitively expensive. Therefore, tests were conducted at a drilling test facility near Cameron, Texas, where operations were conducted over a wide range of rotating speed, weight, and flow conditions and with inclinations ranging from vertical to horizontal. Introduction To reduce implementation risk of drilling directional wells with casing, tests were conducted in a wellbore having a profile similar in complexity (i.e., hole angle, build rate, and depth) to a well to be drilled with 10 3/4- and 7 3/4-in. casing off the Eldfisk B platform offshore Norway. The equipment used for the field trial included the same surface equipment required to modify or adapt the rig in Norway. This procedure mirrored those activities that would be necessary to execute the project on the platform. Safety and training were also integral parts of the project. Potential Casing drilling has demonstrated operational time savings of approximately 15% in straight-hole applications compared with normal drillpipe drilling, and such results are expected in casing directional drilling offshore. Eliminating the need to pick up drillpipe, condition the well, and trip out of the hole to run casing can save a substantial amount of time. Routine trips for bits, underreamers, and measurement-while-drilling (MWD) tests also will provide time savings. However, the major benefit is expected to be minimizing formation-related problem time. Improved hole cleaning in the 10 3/4-in. section should eliminate problems washing casing to bottom and should improve cement jobs. The mud remains well conditioned because the casing is not run in a separate trip. The smear effect should provide significant improvement in dealing with fluid-loss and shale-stability problems in the 7 3/4-in. section. Even in the cases in which losses occur with the casing already on bottom, drilling to the casing point can be achieved and cementing can be performed without having to stabilize the hole. Achievements at Eldfisk similar to those seen in straight-hole casing drilling provide the potential to reduce well times by 5 to 7 days per well. Additionally, if the smear effect is as effective in chalks as it is in sandstones, then a casing string may be eliminated also. Drilling times will, therefore, be reduced further, allowing one to two more wells to be drilled per year. In the longer term, successful casing directional drilling will allow fit-for-purpose rigs and casing-drilling-enabled rigs to be built for offshore use.

Summary The operator and coventurers are developing several Angola Block 15 fields in water depths of up to 1400 m. To date, 83 development wells and 33 exploration/appraisal wells have been drilled in the block. Most have experienced hole quality issues in the riserless interval that are manifested as tight hole while tripping the bottomhole assembly (BHA) and as abnormal/excessive drag while running casing. In a few cases, casing could not be run to total depth (TD), and in one unfortunate case, the casing buckled in open water. There has been uncertainty as to the root cause of the hole-quality issues that have been attributable to various factors since drilling was initiated. A review of available literature revealed very little published information on riserless drilling and casing-running practices. The operator undertook a study of its riserless drilling and casing-running practices to look for trends that may suggest certain sources as the root cause and to allow a re-examination of long-accepted practices. The study, combined with some new perspectives on directional-drilling mechanics, identified micro-tortuosity as the root cause of casing-running difficulties. Micro-tortuosity has been known to exist in deeper, more consolidated sediments. The study revealed that microtortuosity can also exist in large diameter holes drilled in soft sediments. Changes to drilling practices have resulted in improved riserless hole quality and smoother casing-running operations.

Summary The drilling industry is striving to be more efficient, reducing time, costs, and emissions to provide energy solutions for a more climate-conscious world. Reducing nonproductive time (NPT) and invisible lost time (ILT) by utilizing modeling software to optimize tripping operations is one method to combat this. Additional factors such as sea heave have a significant impact on tripping operations on semisubmersible drilling vessels, which do not show a linear response to increased heave. These vessels have compensation systems, but they are often not in use or not completely accurate. Typical heave experienced in the North Sea is between 0.5 and 3-m amplitude and 10–30-second heave period. In this study, transient modeling software is used to create a digital twin of the wellbore to safely predict the tripping speed and define the effect heave has on the tripping operations, from causing additional swab and surge pressures when in or out of slips to reducing tripping speed and improving efficiency by reducing mud gelling at connections. To further understand the effect heave has on tripping operations, experimental simulations of varying heave magnitude were completed in wellbore sections of 0°, 30°, 60°, and 90° inclination. Model validation was completed before running simulations. The results indicate that in horizontal holes, low heave magnitudes result in no bit or pressure response. The same cannot be said for vertical wells, which show smooth bit movement and pressure response throughout the heave magnitude spectrum. However, in a horizontal hole when the wave height is of a larger magnitude, sufficient to break wellbore friction, bit displacement is observed to display jerky axial stick and slip movement, and resultant increased swab and surge pressures are shown even when accounting for the reduced pressure fluctuations due to string eccentricity in an inclined wellbore. It is proposed that much of the related mechanical and pressure response is due to the properties of the drilling mud, string elasticity, and the forced frequency of the waves on the natural frequency of the drilling rig and drillstring. It is clear from definitive and experimental simulations that extra care must be taken when the heave is significant to maintain wellbore stability and reduce wellbore pressure cycling.

The paper describes the improvement in drilling efficiency obtained in five mature North Sea fields, by using a systems approach. The drilling program was managed by a drilling efficiency group consisting of a service company, drilling contractor and operator engineers drawn from several disciplines. All of the well sections were geometrically complex. Data was gathered using downhole pressure and vibration sensors, and acoustic caliper sensors. MWD annular pressure measurements had shown that conventional steerable motor/bit combinations required extensive circulation and occasional back reaming to ensure adequate hole cleaning. MWD vibration measurements and BHA modeling had proved that particularly high levels of vibration were caused by both circulating and back reaming. This was directly associated with MWD, motor and other downhole tool failures. It was concluded that the basic problem was hole quality and attention was directed to eliminating hole spiraling deduced from MWD logs and calipers. A new combination of compatible steerable PDM and long gauge bit was designed with input from the operator. This was designed to achieve improved hole quality from long gauge bits without losing the rapid deviation response of conventional motor/bit combinations. The aim was to improve overall drilling system efficiency, particularly poor hole cleaning, excessive torque and drag, and slow ROP when sliding. The paper discusses the initial data gathering and diagnosis and how measurement and modeling of downhole conditions led to the optimal solution. Comparison between 8 conventionally drilled hole sections and 8 hole sections drilled utilising the new drilling system showed more than 50% reduction in overall drilling time. Significant time savings have been made when drilling in the orientated mode. Other benefits are reduced drilling WOB from 30,000 lb to 3,000 lb, reduced drilling torque and drag, and an overall improvement in hole quality reflected by improved hole cleaning.

The cellular tendon concept described in this paper is an enabling technology proposed for Tension Leg Platforms (TLP) to meet the industry's demands for producing oil and gas in ultra-deep waters beyond 1500 m. The technical merits of the concept for ultra-deepwater field development have been demonstrated in this paper using TLPs with representative large, medium or small payloads in water depths between 1,500 and 3,000 meters. The technical readiness is enhanced by using mature industry products for tendon components, and by adapting existing industry practices to construct and install the Cellular Tendons. The Cellular Tendon has advantages over conventional tendons in technical robustness and economics of the project, as well as enabling/enhancing local fabrication content. The intellectual property of this design concept is protected under a pending global patent. Background Historically, TLPs are ideal platforms for deep water drilling and oil and gas production with dry trees worldwide. Currently there are over a dozen TLPs installed in regions including the GOM, Southeast Asia, and West Africa. Several TLPs are planned for installation in the GOM, North Sea and Brazil in the near future. The application of TLPs with a conventional tendon system has reached technical and economical limit for water depths beyond 1,500 meters. For a TLP in ultra-deep water, the technical and commercial practicality is constrained by the feasibility of the tendon main body and it meeting stiffness and collapse requirements. Also, the cost of conventional tendon installation in certain regions is sometimes prohibitive for the commercial viability of the project. Design of the Cellular Tendon System The Cellular Tendon concept has the same main components as a conventional tendon. A conventional tendon consists of three major parts: a tendon top segment (TTS) interfaces with the platform, a tendon bottom segment (TBS) connects to the tendon foundation at the seafloor, and a main body that links the two through the water column. The Cellular Tendon innovation resides in the design of the main body. Instead of one pipe, it consists of multiple metallic tubules. It also has an upper transition unit to interface with the TTS and a bottom transition unit to interface with the TBS. The top and bottom interfaces—TTS and TBS--are kept the same as in conventional tendons. The same tension-monitoring units in the conventional tendons can be used in the Cellular Tendons as well. Figure 1 is the elevation view of the TLP moored to seabed by the tendons. The tendons are connected to the tendon porch through the top interface and the foundation through the bottom interface. Figure 2 is the schematic of the Cellular Tendon system. Unlike the single carbon steel pipe used as the main body in a convention tendon design, the main body consists of multiple metallic tubular strings. Each individual string is composed of pipes butt welded at their ends. All the strings are arranged in parallel and assembled on-shore. The pipe material can be carbon steel or aluminum. Conventional carbon steel pipes have been used in many existing TLP tendons are considered mature industry practice and are preferred to be used first in the field development. The number of strings in the main body is designed to meet the stiffness requirements, strength requirements, fatigue requirements, and to be practical for fabrication and installation. The outer diameter and/or wall thickness of the pipes can vary along the string. In general, the OD of the pipes is smaller and /or the pipe wall thickness is increased for those segments at greater water depths.

A unique problem of drilling oil and gas wells in deepwater is the narrow window between the formation pore pressure and fracture pressure. The current drilling practice with constant-gradient of drilling fluid requires excessive casing programs and larger, more expensive rigs to drill the formations. Although different techniques, such as dual-gradient drilling, have been used to ease the problem, they are limited to certain geological conditions. This study investigated the possibility of using heavy foam as the drilling fluid to solve the problem. The heavy-foams studied include brine-base foams and barite-water-base foams. We found that the brine-base foams have lower foam stability, density, and quality index. But they have better flow properties. The barite-water-base foams have higher foam stability, density, and quality index. But their flow properties are not as good as the brine-base foams. We conclude that heavy foams can be made to have properties suitable for drilling deepwater wells to reduce casing programs. Use of the heavy foams will create larger boreholes for oil/gas production with much lower cost of well construction. Tremendous savings in the deepwater development are expected with this new technology. Introduction Since the geological evolution in the deepwater is thought to be similar to that in the continental shelf, huge hydrocarbon reservoirs are expected in situ. However prospecting for oil and gas has considerable risks and expenses. One of the major problems encountered is the narrow window between the pore pressure and fracture pressure gradients which occurs with increasing water depth. Typically, in deepwater environments, an increase in depth is accompanied by an increase in undercompaction of sediments, which causes a rise in pore pressures with decreases in both the vertical and horizontal stress gradients, so resulting in a closure of the pore pressure - fracture gradient window. This margin can be so close that a slight decrease in borehole pressure can lead to fluid influx, whilst a slight increase in borehole pressure can result in a loss of circulation (Sangesland, 2006). An excessive number of casings, i.e. 4 - 6 or even more casing strings, may be needed to reach the desired depths, resulting in grossly insufficient borehole sizes making the wells economically impractical. The use of heavy foams as a drilling fluid is investigated to suggest a methodology for drilling in deepwater that minimizes the well control challenges and the limitations that are currently experienced in deepwater operations that allow for drilling longer hole-sections not considered possible with conventional drilling fluids. The purpose of using heavy foams as the drilling fluid would be to control any rapid increase in pressure gradient which could fracture shallower formations especially as experienced in the shallower formations in deepwater. The heavy foam would in essence operate on a similar principle to the dual gradient managed pressure drilling concept, with the higher foam density at the point of drilling and the lower densities further up the wellbore. The dual gradient method involves lightening of the drilling fluid by diversion of the returning fluid to the surface via a separate riser rather than the casing annulus. This diversion seperates the heavy mud above the sea bed from the wellbore, blocking it from exerting its influence on the exposed formation in the well. The hydrostatic head below the mudline is therefore made equivalent to its expected value with the rig at the ocean floor while maintaining sufficiently high drilling fluid density to contain formation pressures. The heavy foam profile would be similar to that of the dual gradient fluid except that it maintains a varying gradient and so drilling can be carried out in a tight operating window between the fracture pressure and the pore pressure to deeper depths before the need to set casing. The main objective of this study is to investigate the possibility of generating heavy foams useful for deepwater drilling. Heavy brine and barite were used for weighting up the drilling fluid in this study. Several foaming agents and several other chemicals were used to form foams in brine with nitrogen gas.

Machine learning (ML) has become a robust method for modeling field operations based on measurements. For example, wellbore cleanout is a critical operation that needs to be optimized to enhance the removal of solids to reduce problems associated with poor hole cleaning. However, as wellbore geometry becomes more complicated, it gets more difficult to predict the cleaning performance of fluids. As a result, optimization is often challenging. Therefore, this study aims to develop a data-driven model for predicting hole cleaning in deviated wells to optimize drilling performance.More than 500 flow loop measurements from 8 studies are used to formulate a suitable ML model to forecast hole cleanout in directional wells. Measurements were obtained from hole-cleaning experiments that were conducted using different loop configurations. Test sections ranged in length from 22 to 100 feet, in hole diameter from 4 to 8 inches, and in pipe diameter from 2 to 4.5 inches. The experiments provided measured equilibrium bed height at a specific flow rate for various fluids, including water-based and oil-based fluids and fluids containing fibers. Several relevant test parameters, including fluid and cutting properties, well inclination, and drilling string rotation speed, were also considered in the analysis. The collected data has been analyzed using the Cross-Industry Standard Process for Data Mining (CRISP-DM). Six different machine learning techniques (Random Forest, Linear Regression, Neural Networks, Multivariate Adaptive Regression Spline, Support Vector Machine, and Boosted Decision Tree) have been evaluated to select the most appropriate method for predicting bed thickness in a wellbore. Also, we compared the predictions of the selected ML method with those of a mechanistic model for cases without drill string rotation. Finally, using the ML model, a parametric study has been conducted to investigate the impact of various parameters on the cleanout performance of selected fluids.Results show the relative influence of different variables on the prediction of cuttings bed. Accordingly, flow rate, drill string rotation, and fluid behavior index have a strong impact on dimensionless bed thickness, while other parameters such as fluid consistency index, solids density and diameter, fiber concentration, and well inclination angle have a moderate effect. The Boosted Decision Tree algorithm has provided the most accurate prediction with an R-square of approximately 90%, Root Mean Square Error (RMSE) of close to 0.07, and Mean Absolute Error (MAE) of roughly 0.05. A comparison between a mechanistic model and the selected ML technique shows that the ML model provided better predictions.

Drilling in the Statfjord Field has become increasingly challenging as remaining oil pockets require designer wells, horizontal wells, or Extended Reach Drilling (ERD) wells with great demand for reservoir navigation in three dimensions. Until recently this has been performed with steerable motor assemblies, with frequent steering difficulties in the reservoir sands. Low rate of penetration (ROP) while sliding has given an overall low drilling efficiency, and in some cases inadequate steering ability has resulted in a less than optimum wellbore placement. Long sliding intervals have also resulted in poor hole cleaning, which has contributed to stuck drill string and lost circulation problems. This paper presents the introduction of a rotary steerable system in the multilateral horizontal well C-23 in the Statfjord Field, and how this improved drilling performance over comparable wells in the reservoir. The following topics are discussed in the paper:–Field description and brief overview of directional drilling challenges in the Statfjord Field.–Statoil's active role in the development of rotary steerable systems.–Functional description of the rotary steerable system, highlighting the technology's benefits compared to traditional directional drilling methods.–Why well C-23 was chosen as a suitable candidate for therotary steerable system, becoming the first successful utilization of this promising technology in the Norwegian Sector.–Case history, emphasizing directional control, drilling efficiency improvement, and other valuable experiences from utilizing the rotary steerable system. P. 313

The anticipation and remediation of operational problems while drilling an oilwell is the main goal of real time measurements of drilling parameters, such as bottomhole pressure, flow rate, pump pressure, torque, drag, among others. The petroleum industry has spent a great amount of financial resources to ensure the quality and availability of these data, but the knowledge for a correct analysis and interpretation of them is still far from being spread among the rigsite teams and drilling engineers. Nowadays, the interpretation of real time drilling data to identify possible operational problems is done by a drilling analysis specialist. However, this can be a very subjective job since it depends on the specialist experience. These analists also take their decisions based on intuition and qualitative rather than quantitative criteria. Petrobras has developed a computational tool (called PWDa) to interpret real time drilling data, predicting and analyzing drilling operational parameters (such as pump pressure, bottomhole pressure, torque and drag). The software detects abnormal behaviors (such as an unexpected increasing trend on bottomhole pressure) and establishes quantitative criteria in order to identify a possible cause, suggesting corrective and/or preventive actions. The main goal of the software is the establishment of an automated methodology to interpret operational parameters in real time helping the drilling engineers to take right and fast decisions. The software is being currently implemented at Petrobras Real Time Operations (RTO) rooms and is providing good results. Over 70 wells have already been monitored with PWDa and several operational problems (such as washout, mud losses, bit wear, downhole motor fail, deficient hole cleaning, pore pressure increments, etc) were successfully identified, allowing the operators to take fast decisions and avoiding riskier situations. The wells monitored include deep water exploratory wells (mostly), directional development wells and extended reach wells. This work aims to highlight the benefits generated by the implementation of the technology. The interaction with the drilling team, including operator and service company members will be discussed. Introduction The analyzis of PWD (Pressure While Drilling) data and other operational parameters (such as rate of penetration, standpipe pressure, flow rate, torque, drag, etc) is an important tool to identify and prevent several operational problems (Aragao et al). The real time interpretation of these data may be very useful to reduce non productive time, risks and operational costs. According to Teixeira et al, most of events and problems have direct or indirect impact on bottomhole pressure and standpipe pressure. Some of them may also affect torque and drag. Problems like poor hole cleaning, annular obstructions, wellbore collapse, kicks, washouts and mud losses will affect the amount of solids in the annular space and/or friction losses and, therefor, will directly affect standpipe and bottomhole pressure (Aragao, et al, 2005). Thus, the analysis of pressure data is a key element to identify and prevent operational problems. Additionaly, when other parameters are simultaneously analyzed (modlogging measurements, for instance), the interpretation becomes much richer.

This paper presents an autonomous drilling advisory system powered by digital twins and AI solutions. Such an advisory system aims to automate real-time monitoring and parameter optimization, reduce subject-matter experts, and meet the demands for safer and more efficient drilling toward autonomous operation. The methodology proposed in this research involves the creation of a comprehensive Digital Twin model that accurately replicates the drilling process by integrating hydraulic, thermal dynamic, and mechanical models. To ensure high model accuracy, an auto-calibration approach is developed, driven by real-time data, to fine-tune the Digital Twin models. Additionally, AI-based model reasoning techniques are employed to detect potential hazards and risks ahead of the bit proactively. This is achieved by comparing the ideal behavior of the digital twin replica with the actual behavior observed from downhole and the rig. As a result, real-time diagnostics are generated to supervise ongoing operations, accompanied by suggestions to mitigate identified risks. Furthermore, the system leverages the capabilities of the Digital Twin and optimization methods to create multiple combinations of operational parameters. These parameters are optimized by ranking the predicted performance derived from the Digital Twin. The optimized operational parameters are automatically generated as forward advice to drillers, enabling them to make informed decisions and enhance drilling performance. Testing results on multiple wells from different operators are presented, showcasing the system's capabilities in real-time monitoring and drilling parameter optimization. The system demonstrates its effectiveness in providing diagnostic messages with early anomaly detection during drilling and casing running. These diagnostic warnings include losses, leakage, poor hole cleaning, and stuck pipe, enabling proactive intervention to mitigate risks. Furthermore, the system optimizes operational parameters during drilling and tripping in real-time without requiring human intervention. This optimization covers parameters such as flow rate, rotary speed (RPM), and rate of penetration (ROP) during drilling, and tripping speed during tripping in and pulling out of the hole. The time savings achieved through the use of optimized parameters are quantified for both cases, demonstrating a substantial improvement in operational efficiency while maintaining safety margins. The scalability and adaptability of the system are also highlighted, emphasizing its ability to accommodate diverse drilling scenarios and integrate with existing solutions in various deployment conditions. The proposed methodology demonstrates the development of a robust and efficient system that enhances decision-making and improves drilling performance. In addition, the results highlight the potential benefits of combining AI and Digital Twin technologies in the drilling industry, paving the way for future innovations and advancements in the field.