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Collaborating Authors
Halliburton
Machine Learning Algorithm Autonomously Steered a Rotary Steerable System Drilling Assembly Delivering a Complex 3D Wellbore in Challenging Downhole Drilling Environment: A Case Study, Malaysia
Mad Said, Saiful Haq B. (PETRONAS) | M. Mokhti, M. Ridzuan B. (PETRONAS) | Arumugam, Sathiaseelan B. (PETRONAS) | Kok, Keng Hung B. (Halliburton) | Sidek, Rosli B. (Halliburton) | Ow, Jonathan B. (Halliburton) | Ahmad, Mohd Arza (Halliburton)
Abstract Deviated oil and gas wellbores were drilled by competent and experienced directional driller (DD) to deliver the wellbore's trajectory on target and on time. The variable human factor and rapid changes of various surface and downhole parameters present challenges for consistent performance every time. A dynamic physics-based machine learning (ML) algorithm leverages on digital twin data analytics and real-time downhole measurement to autonomously steer Rotary-Steerable System (RSS) drilling assembly was employed. This case study describes the methods, the algorithm learning, assimilates the data in real-time, and autonomously steers. Operator's in-field redevelopment plan consists of drilling two oil producers and one water injector side-tracking from donor wells. Due to congested nature of the platform with many producing wells through multi-stacked reservoirs, the wellbore profiles are complex 3D to tap into the various reservoir target sands and avoiding close approach to nearby drilled well. Meticulous well engineering and Bottom-Hole-Assembly (BHA) analysis were performed during the pre-drill planning stage to ascertain the directional performance of the RSS BHA, sensitivity study, offset directional performance and risks were thoroughly assessed. The autonomous steering algorithm models the directional performance tapping into the vast database of digital twin, expected directional performance, evaluates past yields, projecting ahead and constantly adjusting parameters such as steering aggressiveness, dogleg severity, turn rate, whilst staying within safety margin of anti-collision if any to deliver the wellbore to target. The speed of the computation from downhole sensor measurement, coupled with high-speed telemetry of the data to the surface allows for systematic increased in speed of real-time data processed, culminating to ML autonomous steering for RSS BHA to deliver a smoother wellbore that is not possibly with human manual calculation. The complex 3D well profile entails building wellbore angle from 40 degrees to 80 degrees before dropping to 67 degrees while turning azimuth from 190 degrees to 85 degrees with 3.5 degree per 30 meters dogleg severity. After initially side-tracking performed manually by the Directional Drillers at the rig site, autonomous steering algorithm was executed to directionally drill the wellbore through all the planned geological targets till well's total depth. 1224 meters were successfully drilled in autonomous mode without any DD intervention for 3 days of drilling with average 30-45 meters per hours rate-of-penetration. This resulted in 97 percent of wellbore autonomously steered and placed optimally through all planned geological targets, with 32 percent faster drilling compared to offsets. Eighty-six autonomous closed loop steering command flawlessly executed downlink saved fourteen hours of rig time, eliminating invisible loss time translating to faster on bottom drilling. The digital transformation with advances in ML and artificial intelligence, provided impetus drilling automation, to a paradigm shift on how we traditionally drill directional wellbores.
- Asia > Malaysia (0.83)
- North America > United States > Texas (0.69)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Spindletop Field (0.99)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Block PM 6 > Dulang Field (0.99)
IADC Code Upgrade: Data Collection and Workflow Required to Conduct Bit and BHA Forensics to Create Effective Changes in Practices or Design
Watson, William (Shell) | Dupriest, Fred (Robert Gordon University (Corresponding author)) | Witt-Doerring, Ysabel (Texas A&M University) | Sugiura, Junichi (Halliburton) | Pastusek, Paul (Sanvean Technology) | Daechsel, Dustin (Exxon) | Abbas, Raafat (Shell) | Shackleton, David (Chevron) | Amish, Mohamed (Independent Data Services)
Summary This paper introduces a forensic workflow that can be used to link drill-bit and bottomhole assembly (BHA) damage to drilling dysfunction. This paper will also discuss the data that should be collected and how it should be processed to enable operational practices and engineering design changes to address these issues. There is a vast amount of data collected in all drilling operations that can be used to improve performance if utilized within an effective forensic workflow. Several drilling forensic case studies were developed and critically reviewed by subject matter experts from across the industry. From the causal analysis for each case study, an assessment was performed on what information was (1) available, (2) required to diagnose the cause, and (3) not available but would have been preferred. The way the team communicated and acted on the data was also documented. By combining the learnings from these case studies, it was observed that a guided approach can improve data collection and lead to a more consistent, accurate, timely, and causal analysis with appropriate remedial actions. The process discussed within has been refined to support data collection for forensic analysis and provides a reference for field- and office-based drilling professionals. These practical guidelines have been developed to offer a foundation for a drilling forensic data collection methodology as well as training for the industry—they have been created such that they can grow organically and will form part of the International Association of Drilling Contactors (IADC) Bit Dull Grading Recommended Practice to support the IADC dull grade manual. In the future, these can be used for developing subsequent industry publications. The work described in this paper is part of a joint IADC/Society of Petroleum Engineers industry effort to revise the IADC dull grade manual.
- North America > United States > Texas (0.95)
- Europe (0.93)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type (0.68)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > North Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OML 95 > Meta Field (0.93)
Infused Scale-Inhibitor Proppant Ensures Sustained Production Assurance Strategy Against Scale Deposition in Multi-Fractured Wells
Giammancheri, M. (Eni SpA Natural Resources) | Tassone, G. (Eni SpA Natural Resources) | Carpineta, Gabriel. (Eni SpA Natural Resources) | Magna Detto Calcaterra, M. S. (Eni SpA Natural Resources) | Magri, R. (Eni SpA Natural Resources) | Itoua, R. (Eni SpA Natural Resources) | Okoka, A. (Eni SpA Natural Resources) | Luppina, S. (Eni SpA Natural Resources) | Pollio, P. (Eni SpA Natural Resources) | Saldungaray, P. (CARBO Ceramics Inc) | Annovi, E. (CARBO Ceramics Inc) | Ilyasov, R. (Halliburton) | Reilly, B. (Halliburton)
Abstract This paper describes the production assurance strategy adopted to resolve scaling deposition in hydraulically fractured wellbores by means of incorporating a ceramic proppant infused with a controlled release scale inhibitor in the primary completion. This chemical delivery system has been applied as an integral component in the offshore field development program and yielded positive results. Production assurance and scale inhibition chemicals are traditionally injected via a dedicated capillary in the production string, but this approach is often not very efficient or effective as a prevention strategy due to the uncertainty surrounding the severity and timing of the phenomenon. Contributing factors to the scale deposition include variations in the water production rate, water breakthrough from water flooding and changes in the bottom hole flowing pressure and temperature. These variable conditions also complicate the scaling prediction efforts. A ceramic proppant based chemical delivery system was selected to ensure multiyear inhibition of scale with a onetime treatment. The engineered ceramic proppant provides effective chemical delivery, high fracture conductivity and strength so it can be used to replace part of the proppant in hydraulic fracturing and frac pack completions or be incorporated into a gravel pack completion. The strategy was successfully applied in a field in West Africa. Significant learnings from this implementation of controlled release scale technology in the primary completion was realized. The controlled release of the scale-inhibiting chemical into the production stream as it flows through the proppant pack effectively prevents scaling in the fracture, the wellbore, and completion string to surface. The key concept was to eliminate the uncertainty surrounding the onset of the scaling problems, which inevitably results during well selection process due to the variation in water production and chemistry among the wells. Another important goal was to also reduce the frequency of costly interventions in an offshore operating environment and to maximize well and field production uptime. The field application of this delivery system has successfully eased the operational challenges being observed in offset wells which otherwise require repeated treatments of scale inhibitor. Operational benefits resulted from the increased free space on the platform and eliminated any need of well interventions for remedial scale control on these treated wells. The information presented in this paper will benefit production engineers facing similar scale and production challenges and seeking a comprehensive production assurance strategy and desire a cost-effective solution. The application of infused scale inhibitor proppant has shown to provide production assurance as a onetime treatment, regardless of well type, and can provide a sustained multi-year scale prevention solution.
- North America > United States > Texas (0.29)
- Asia > Middle East > Saudi Arabia (0.28)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Utah > Uinta Basin (0.99)
- North America > United States > Colorado > Uinta Basin (0.99)
- (2 more...)
A Holistic Approach to Data Interpretation Combines the Strengths of Ultra-Deep Electromagnetic Tools with Shallow Logging While Drilling Data to Improve Reservoir Understanding
Riofrío, K. (Halliburton) | Clegg, N. (Halliburton) | Rawsthorne, L. (Aker BP) | Kolstø, S. (Aker BP) | Mouatt, J. (Aker BP) | Bang, A. (Aker BP) | Chatterjee, A. (Aker BP)
Abstract Understanding the geological setting and architecture in which a well is drilled is key to achieving optimal well placement, enhancing reservoir production and for future reservoir exploitation with the planning of additional wells. The planning of production wells is accomplished using different data sets with different resolutions, but understanding the subsurface geology is key to linking the data sources. During drilling operations LWD tools, which have greater resolution than seismic, are deployed to aid in decision making and optimise well placement. Focusing on the data sources in isolation can lead to successful wells, but placing this data in a geological context allows for more sophisticated decision making and leads to greater reservoir understanding for improved reservoir exploitation. Key to linking the near wellbore measurements with the geological models derived from seismic interpretation are ultra-deep electromagnetic (EM) tools. Applying geophysical inversion processes to the ultra-deep resistivity data generates models that enhance the reservoir interpretation. Formation boundary identification and definition of thin layers in the vertical plane can be achieved with 1D EM inversion. Combining these results with a Gauss-Newton-based 3D inversion provides better identification of the reservoir lateral variability. Recently the introduction of inverting the 3D EM inversion for anisotropy as well as resistivity, permits the identification of isotropic and anisotropic intervals allowing lithological and fluid identification at greater distances from the borehole. The geological models derived from the inversion data can provide a good representation of the subsurface but are more useful for decision making when correlated with other LWD data and azimuthal images, for example density and gamma ray. These tools have a much shallower range of detection but provide more detail which can be critical when placed in its geological context. Combining all available technologies to improve reservoir understanding of different depositional environments is a more effective approach. Interpretation of the 1D, 3D and 3D anisotropy inversions both allows identification of complex oil water contacts which is vital for hydrocarbon reserves calculation and in certain environments, identification of intra-reservoir thin shale layers that can act as a baffle of fluid movement. Refining these models with the information available from density/neutron, gamma and deep EM data provides a greater level of detail which can also play an important role in the completion design process. The improved reservoir understanding derived when combining the interpretation of these diverse methodologies can provide a better understanding of the geological scenarios and allows the identification of elements that play a role in well and field production. Identifying these trends during the drilling operations allows for both optimization of the well placement and completion installation. Further analysis post well allows improved reservoir exploitation and planning of new wells.
- North America > United States (0.68)
- Asia (0.68)
- Europe > Norway > North Sea (0.47)
- Phanerozoic > Mesozoic (0.68)
- Phanerozoic > Cenozoic > Paleogene (0.46)
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.70)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Electromagnetic Surveying > Electromagnetic Modeling > Electromagnetic Inversion (0.55)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > Våle Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > A2 North Heimdal T60 Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Hermod Formation > Våle Formation (0.99)
- (27 more...)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- (3 more...)
The Evolution of UDAR Technologies for Risk Mitigation in Geostopping Applications
Sinha, Supriya (Equinor) | Antonsen, Frank (Equinor) | Clegg, Nigel (Halliburton) | Walmsley, Arthur (Halliburton) | Vicuña, Brígido (Halliburton) | Danielsen, Berit Ensted (Equinor) | Constable, Monica Vik (Equinor) | Prymak-Moyle, Marta (Equinor)
Abstract Complications during drilling and completion operations caused by subsurface geology have a significant impact on rig time, cost, assets, and even human life, if risk and incident severity is not well understood. Risk and tolerance evaluation processes are essential for completing successful drilling programs and final casing designs. While log-based correlation methodologies can be used, they are limited to scenarios where appropriate offset well data control exists, and they only provide information after the hole has been drilled. The development of technologies that provide warning of a hazardous zone before it is penetrated are therefore desirable. Ultradeep Azimuthal Resistivity (UDAR) tools are deployed for such scenarios and provide high value when used in integrated interpretations to identify hazards ahead of drill bit. Seismic data is used as a first step to predict and map subsurface characteristics such as pressure regimes, faults, and fluid contacts. Offset and pilot hole data further complements assessment of these features enabling more precise risk assessment. Commonly, near-bit measurements such as resistivity and gamma ray have been used for these correlations in conjunction with sonic and density measurements. The mapping of horizons from seismic data can have 10s to 100s of meters of vertical uncertainty, while offset data in exploration campaigns is typically sparse and near-bit measurements require drilling into the zone of risk. Pilot holes therefore become a costly necessity, however, if sufficient resistivity contrast exists UDAR can be used for remote boundary mapping, without drilling into the geohazards, thus reducing cost and de-risking the operation. This paper presents several case studies where UDAR technology was deployed in near vertical to horizontal wells to map geohazards before they were penetrated using different techniques, allowing optimization of the stopping point in diverse scenarios. This includes a case where the technology was used to geostop in a horizontal section prior to penetration of a major structural sealing fault plane that bounded the productive reservoir interval. UDAR has been successfully used to manage seismic uncertainty, support the decision-making process for core point selection, reduce exposure of unstable overburden shales and geostop above abnormal and subnormal pressure zones. Mapping a geohazard and proactively stopping at a particular depth is a complex operation and evaluation of the rock properties with respect to the sensitivity of the measurements and uncertainty in the models is important. Limitations in measurement sensitivity can lead to potential masking of top reservoir picks and increased uncertainty in both boundary positions and the inverted resistivity. Improvements such as new UDAR transmitter designs being embedded into Rotary Steerable Systems allow near-bit placement of this technology, demonstrating the continual evolution of this technology and how it assists risk mitigation in geostopping applications.
- North America (1.00)
- Asia (0.93)
- Europe > United Kingdom (0.67)
- Geology > Structural Geology > Fault (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.48)
- Geology > Geological Subdiscipline > Stratigraphy (0.46)
Chemical Descaling to Restore Full Wellbore Access and Hydrocarbon Production: Use of 10% Hydrochloric Acid System and Customized Bottom Hole Assembly to Remove Deposited Scales on the Tubing Walls
Bougha, Arthur (SPDC) | Iyengumwena, Ricky (SPDC) | Alalade, Temitope (SPDC) | Okeke, Chinyere (Halliburton) | Ndukauba, Godian (Halliburton) | Abudu, Rahman (Halliburton)
Abstract Solids deposits is commonly experienced in oil field well tubulars mostly in mature fields where the wells have been produced over time. Full wellbore access is required to execute most thru-tubing intervention activities. It is also imperative that well production is restored to sustain the asset value of the operator. Restoring and sustaining production from brown field reservoirs has often proven to be critical to the success of oil and gas companies across the world. These increases in oil production are often achieved through various well intervention techniques. The relative instability in global oil prices makes such activities hugely attractive in the oil and gas sector as they are typically a lot cheaper than new well developments which also come with the inherent risks associated with drilling and completions operations. The key objective here was to descale a well with deposited scales in the tubing which prevented downhole intervention and also led to production deferment. The well intervention targeted at improving the production from Well AA-052 in the Niger Delta region of Nigeria was initially planned as a slickline gas lift valve change out due to the observed issues with the vertical lift performance of the string. However, difficulties were experienced during the execution of the gas lift valve change out. Debris and scales present in the wellbore hindered access of the slickline tools deployed to achieve the gas lift valve change out. As a result, the activity was temporarily aborted In this paper, the detailed planning and execution of AA-052 is addressed. With the debris recovered from the well, an extensive laboratory testing to ascertain the nature of solid deposit was conducted. These scale deposits were confirmed from the laboratory tests to be mainly calcium carbonate, hence a tailored fluid system consisting of 10% Hydrochloric acid was identified to effectively dissolve and remove the solid deposits. The treatment was deployed via Coiled Tubing utilizing a rotating downhole tool which provided additional mechanical means with 360 degrees coverage. The combination of the chemical treatment and mechanical means (rotating downhole tool) provided an effective and efficient descaling of the wellbore. The key project deliverable was achieved as the full wellbore access was regained. Production was also restored as the well which originally had a shut-in tubing head pressure of 0psi has now increased to 1,360psi post the chemical descaling. The earlier attempt to carry out a planned slickline gas-lift valve change was suspended due to the wellbore access challenge as a result of the scale build-up. However, post the chemical descaling activity, the planned slickline gas-lift valve change out activity was successfully carried out. Initial production post chemical descaling was 1,000bopd. With the gas-lift valve change out executed, an additional gain of 200bopd in production was achieved. The well is currently producing with ca.1,200bopd with a recoverable volume of 0.93 MMstb reserves. This paper represents a typical case of flawless diagnostic, design and delivery process. Getting a scale sample and performing an extensive laboratory testing and fluid selection was key to the successful descaling operation. Utilizing Coiled tubing for pinpoint treatment by reciprocating across the solid build up sections while pumping 10% HCL acid through an incorporated high jetting and rotating tool made it most effective
- Africa > Nigeria (0.88)
- North America > United States > Texas > Dawson County (0.24)
Borehole acoustic full-waveform inversion
Tang, Huaigu (Southern University of Science and Technology) | Cheng, Arthur Chuen Hon (The Chinese University of Hong Kong) | Li, Yunyue Elita (Purdue University) | Fang, Xinding (Southern University of Science and Technology) | Wang, Ruijia (Halliburton) | Wu, Xiang (Halliburton)
ABSTRACT Full-waveform inversion (FWI) is a technique that has the potential for building high-resolution elastic velocity models. We apply this technique to wireline monopole acoustic logging data to image the near-wellbore formation velocity structures, which can be used in a fluid intrusion evaluation. Our FWI workflow is established in cylindrical coordinates instead of Cartesian coordinates to adapt to the borehole geometry. Assuming that the acoustic logging tool is centralized and formation properties are azimuthally invariant, we can simplify the problem to two dimensions in the inversion. Synthetic tests find that the high-resolution P- and S-wave velocity model around the borehole could be successfully inverted using FWI once a reasonable starting velocity model is given. However, borehole FWI differs from seismic FWI in that strong borehole-guided waves exist near the borehole wall due to the elastic effects. The borehole-guided waves have little sensitivity to velocity away from the borehole wall. In addition, it is difficult to simultaneously match the waveform of the body waves and guided waves in synthetic data and field data. Therefore, for field data applications, we propose to obtain the formation velocity structures around the borehole by FWI using only the first arrived P waves. The field data tests find that the proposed method is applicable for inverting the P-wave velocity structure around the borehole with a similar resolution compared with ray-tracing tomography. FWI may achieve higher resolution in field applications in the future with better assumptions made in the forward modeling and using more information in the field data.
- Asia > Singapore (0.28)
- Asia > China (0.28)
- North America > United States (0.28)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (1.00)
- Geophysics > Borehole Geophysics (1.00)
Borehole acoustic full-waveform inversion
Tang, Huaigu (Southern University of Science and Technology) | Cheng, Arthur Chuen Hon (The Chinese University of Hong Kong) | Li, Yunyue Elita (Purdue University) | Fang, Xinding (Southern University of Science and Technology) | Wang, Ruijia (Halliburton) | Wu, Xiang (Halliburton)
ABSTRACT Full-waveform inversion (FWI) is a technique that has the potential for building high-resolution elastic velocity models. We apply this technique to wireline monopole acoustic logging data to image the near-wellbore formation velocity structures, which can be used in a fluid intrusion evaluation. Our FWI workflow is established in cylindrical coordinates instead of Cartesian coordinates to adapt to the borehole geometry. Assuming that the acoustic logging tool is centralized and formation properties are azimuthally invariant, we can simplify the problem to two dimensions in the inversion. Synthetic tests find that the high-resolution P- and S-wave velocity model around the borehole could be successfully inverted using FWI once a reasonable starting velocity model is given. However, borehole FWI differs from seismic FWI in that strong borehole-guided waves exist near the borehole wall due to the elastic effects. The borehole-guided waves have little sensitivity to velocity away from the borehole wall. In addition, it is difficult to simultaneously match the waveform of the body waves and guided waves in synthetic data and field data. Therefore, for field data applications, we propose to obtain the formation velocity structures around the borehole by FWI using only the first arrived P waves. The field data tests find that the proposed method is applicable for inverting the P-wave velocity structure around the borehole with a similar resolution compared with ray-tracing tomography. FWI may achieve higher resolution in field applications in the future with better assumptions made in the forward modeling and using more information in the field data.
- Asia > Singapore (0.28)
- Asia > China (0.28)
- North America > United States (0.28)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (1.00)
- Geophysics > Borehole Geophysics (1.00)
Long Interval Chemical Consolidation of Failing Clay Laden Formations: A Departure from Epoxy-Based Resins
Recio, Antonio (Halliburton) | Benoit, Denise N (Halliburton) | Sanders, Michael W (Halliburton) | Nguyen, Philip D (Halliburton)
Abstract Thermally-activated, single-component resin formulations in which the catalyst is included in the resin composition can be challenging to place over intervals longer than 30 feet (9.1 meters). Despite the proven consolidation performance observed with epoxy-based systems, initial viscosity and rapid reactivity leading to short placement times have resulted in the industry seeking alternative chemistries to enhance formation integrity. Herein we report the development of a 2-stage formation consolidation system entailing a hetero-aromatic-based resin composition that, once placed downhole, will only begin curing with subsequent introduction of an activation fluid. The latent property of the updated resin formulation allows for extended lateral applications, and incorporating a new surface modifying agent allows for the treatment of formations with an excess of 20% wt—clay mineralogy.
- Asia (0.68)
- Africa > Nigeria (0.68)
- North America > United States > Texas (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.66)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 359 > Mahogany Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 349 > Mahogany Field (0.99)
- North America > United States > Alaska > North Slope Basin > Umiat-Gubik Area > Umiat Field > Tuluvak Formation (0.99)
- (5 more...)
ABSTRACT The development of digital infrastructure in the oil and gas industry has led to the proliferation of advisory systems that provide recommendations in real time to mitigate a variety of risks. To deliver their full potential, these advisory systems need to coexist on a common platform across vendors and disciplines (e.g., hydraulic and pressure management, directional drilling, mechanical integrity of the drilling system, and vibration mitigation). Despite the rise of closed-loop automation, however, there is a lack for a scalable tool or platform that can orchestrate multiple digital advisors to coordinate sometimes-conflicting recommendations. Whilst industry players are well versed about determining recommendations, the conventional approach for this problem has been rule- and experience-based. That methodology is not scalable nor transferable. Through this paper we present a framework that structures the process of determining a unified recommendation in real time by integrating the advice from multiple independent digital advisors. The novelty of the approach resides in its ability to structure the process of determining safe and robust recommendations using a scalable and computationally inexpensive algorithm that can run on standard engineering computers at the rig site and virtual-remote-operations centers. INTRODUCTION Digital transformation has become an indispensable and significant part in drilling engineering. The digital transformation sweeping through the industry has led to the development of a variety of applications and algorithms to help drive drilling efficiencies, offset-well learning, and automated detection and interpretation of drilling events and dysfunctions. However, this global push has led to multiple challenges, discussed below. Different teams, divisions, entities, and companies have developed differing solutions that target similar or complementary problems, and the differing solutions may not be compatible or combinable. These solutions can rely on different methodologies (e.g., data-based, physics-based, or hybrid) and can have different technology readiness levels. Some solutions can have conflicting objectives that need to be harmonized to provide a consistent set of actions, such as advisory drilling parameters for automating operations. Typical examples are rate of penetration (ROP) that is typically to be maximized while not exceeding a technical threshold from a hole cleaning point of view, or drilling parameter targets and limits from directional, mechanical, or hydraulic objectives that can conflict as they seek to optimize different aspects of the drilling process. For instance, a vibration advisor (a case study is shown in (Greenwood (2016a,b))) can recommend increasing the rotations per minute (RPM) of the drill pipe and reducing the weight-on-bit (WOB) if a stick/slip vibration occurs. However, from a hole cleaning and pressure management standpoint it may not be advisable to increase the RPM because doing so might exceed the equivalent circulating density (ECD) limit. Similarly, to mitigate a bit bounce or whirl vibration, the advisor can recommend decreasing the RPM, whereas from a hole cleaning point of view the RPM can be recommended to be increased to achieve the target ROP under current average conditions. During such conflicting scenarios it can be difficult for a user or an automation platform to consistently determine the best recommendation from a drilling efficiency standpoint. There may not be a cohesive framework that encompasses the above challenges and the other factors that go into the well construction decision process. Also, there may not exist a common platform where independent advisory systems from different vendors and disciplines can coexist and an open composite advice produced in real time by integrating their recommendations.