The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Zhu, Jun (Vertechs Energy Group) | Zhang, Wei (Vertechs Energy Group) | Zeng, Qijun (Vertechs Energy Group) | Liu, Zhenxing (Vertechs Energy Group) | Liu, Jiayi (PetroChina Southwest Oil & Gas Field Company) | Liu, Junchen (PetroChina Southwest Oil & Gas Field Company) | Zhang, Fengxia (PetroChina Southwest Oil & Gas Field Company) | He, Yu (PetroChina Southwest Oil & Gas Field Company) | Xia, Ruochen (PetroChina Southwest Oil & Gas Field Company)
Abstract In the past decade, the operators and service companies are seeking an integration solution which combines engineering and geology. Since our drilling wells are becoming much more challenging than ever before, it requires the office engineer not only understanding well construction knowledge but also need learn more about geology to help them address the unexpected scenarios may happen to the wells. Then a novel solution should be provided to help engineers understanding their wells better and easier in engineering and geology aspects. The digital twin technology is used to generate a suppositional subsurface world which contains downhole schematic and nearby formation characteristics. This world is described in 3D modelling engineers could read all the information they need after dealt with a unique algorithm engine. In this digital twin subsurface world, the engineering information like well trajectory, casing program, BHA (bottom hole assembly) status, are combined with geology data like formation lithology, layer distribution and coring samples. Both drilling or completion engineers and geologist could get an intuitive awareness of current downhole scenarios and discuss in a more efficient way. The system has been deployed in a major operator in China this year and received lot of valuable feedback from end user. First of all, the system brings solid benefits to operator's supervisors and engineers to help them relate the engineering challenges with according geology information, in this way the judgement and decision are made more reliable and efficiently, also the solution or proposal could be provided more targeted and available. Beyond, the geology information from nearby wells in digital twin modelling could also provide an intuitional navigation or guidance to under-constructed wells avoid any possible tough layers via adjusting drilling parameters. This digital twin system breaks the barrier between well construction engineers and geologists, revealing a fictive downhole world which is based on the knowledge and insight of our industry, providing the engineers necessary information to support their judgement and assumption at very first time when they meet downhole problems. For example, drilling engineers would pay extra attention to control the ROP (rate of penetration) while drilling ahead to fault layer at the first time it is displayed in digital twin system, which prevent potential downhole accident and avoid related NPT (non-production time). The integration of engineering and geology is a must-do task for operators and service companies to improve their performance and reduce downhole risks. Also, it provides an interdisciplinary information to end user for their better awareness and understanding of their downhole asset. Not only help to avoid some possible downhole risks but also benefit on preventing damage reservoir by optimizing the well construction parameters.
Santoro, D. (ENI SpA, San Donato M.Se, Milan - ITALY) | Forno, L. Dal (ENI SpA, San Donato M.Se, Milan - ITALY) | Ferrara, P. (ENI SpA, San Donato M.Se, Milan - ITALY) | Bianchini, L. P. (ENI SpA, San Donato M.Se, Milan - ITALY) | Bartucci, G. (ENI SpA, San Donato M.Se, Milan - ITALY) | Bianchi, L. (ENI SpA, San Donato M.Se, Milan - ITALY) | Lahou, K. (eDrilling, Stavanger - NORWAY) | Nabavi, J. (eDrilling, Stavanger - NORWAY) | Huseynov, P. (eDrilling, Stavanger - NORWAY) | Gocmen, E. B. (eDrilling, Stavanger - NORWAY) | Lye, J. (eDrilling, Stavanger - NORWAY) | Loh, J. (eDrilling, Stavanger - NORWAY)
Abstract Well simulator technologies have become an ever more important part of Well Construction design and Drilling Operations follow-up worldwide. Adopted initially by Company to support personnel training through virtual environment applications, they were then used for planning, real time support and post job analysis for drilling operations, being integrated in all engineering processes. This paper presents an overview of its current use and procedures, highlights current and potential benefits and suggestions for future developments. Selected wells are configured inside the well simulator which is then latched to mud log data streams. Dynamic models calibration is performed by adjusting dedicated coefficients to reach an overlap between simulated and measured drilling parameters. The degree of drift between curves allows to identify well operations-related issues. Outputs are mostly time-based, in mud log and driller-cabin-like layouts fashion. Depth-based plots, such as roadmaps for axial and torsional friction factors are also available and can be used as input for advanced analyses for both planning and post job phases. Systematic application of the well simulator was started early 2021 with real time monitoring for North Sea and Africa offshore/subsea operations. Deployment along 2022 spread out across several other business units in various operated countries, for onshore, offshore and subsea drilling operations. Experience gained in a number of relevant case histories, dedicated to both real time support and what-if post-analyses, allowed to provide earlier feedbacks on drilling operations good practice but also to predict, avoid and mitigate consequences of wellbore problems and equipment malfunctions, boosting interest for further developments. Nowadays, well simulator technologies constitute a fundamental step towards drilling automation, since their dynamic modelling approach allows the definition of drilling parameter envelopes inside which robotic tools can operate and generate alerts if envelopes are overridden. Anomalous behavior of the drilling parameters can be recognized and governed. Automatic configuration and calibration of real time driven models are key enablers of real time optimization of operational drilling parameters and contactless operations, reducing back-office support to minimum. Well simulator solutions that have been tested and deployed in our operations allow adaptability to a variety of existing platforms from both the operators and service companies side. The new upgrades, for data input and results visualization, are prone for user-friendly application, reducing the amount of training required for operative personnel to familiarize themselves with the tool and apply it during drilling operations.
Ekpe, J. (KOC Kuwait Oil Company) | Al-Shehab, A. Y. (KOC Kuwait Oil Company) | Al-Othman, A. (KOC Kuwait Oil Company) | Baijal, S. (KOC Kuwait Oil Company) | Nguyen, K. L. (KOC Kuwait Oil Company) | Al-Morakhi, R. (KOC Kuwait Oil Company) | Dasma, M. (KOC Kuwait Oil Company) | Al-Mutairi, N. (KOC Kuwait Oil Company) | Verma, N. (KOC Kuwait Oil Company) | Quttainah, R. B. (KOC Kuwait Oil Company) | Janem, M. (Reservoir Group/Corpro) | Deutrich, T. (CORSYDE International) | Wunsch, D. (CORSYDE International) | Rothenwänder, T. (CORSYDE International) | Anders, E. (CORSYDE International) | Mukherjee, P. (MEOFS Middle East Oilfield Services)
Abstract The successful recovery of pressurized core samples from an unconventional HPHT reservoir is presented. Optimized methods and technologies such as implementation of Managed Pressure Drilling (MPD) technique as well as coring technology customization and adaptation are discussed. Results from offset wells are compared and a best practice method is described how to recover pressurized cores from the organic rich Najmah Kerogen in West Kuwait. A coring BHA was configured using a modified version of the LPC Core Barrel hence allowing for the first time to consider recovering pressurized core samples from a well with a very challenging operating envelope. Furthermore, the provided methodology ensures that well conditions are maintained to allow for a pressurized core recovery in most stable wellbore environment avoiding any unwanted subsurface problems. With three consecutive runs planned on for the pressurized coring using MPD each 10 ft., the results obtained showed a successful coring operation of which typical wellbore downhole issues were avoided with no loss time due to well ballooning, mud losses and well kicks. The successful coring operations as well as all subsequent on-site analysis procedures showed possibility to recover pressurized core samples from unconventional formations with high formation pressure in a safe and effective manner. Avoiding core damage due to petal-centerline fractures and disking is fundamental in quantifying natural fractures in this unconventional reservoir. This novelty approach of core barrel system modification and using MPD technique in acquiring the pressurized cores has made it possible to obtain representative near in-situ data to better reservoir interpretation and quantification of natural fractures. The method has a great potential to ensure high core recovery in high angle wells while delivering superior reservoir fluid and rock information which is not obtainable by other means.
Abstract Most field engineers and geoscientists find the estimation of borehole salinity using multiple mud reports to be a tedious task. The existing process involves using spreadsheets with multiple charts for conversion and requires the user to juggle from charts to reports to calculators at the same time. Depending on the mud vendor, the standard of estimation and equations change, making the process more user intensive. However, these equations can be strategically used in a programming language to automate this exhaustive and manual process of estimation. Any open-source code editor can be used to run the codes and generate borehole salinity at any depth desired. Borehole salinity is an important parameter as it influences the correction of neutron porosity and associated measurements to be used for petrophysical evaluation. In this study we first outline the current industrywide used methodology of estimating borehole salinity using mud reports supplied by vendors. The input parameters, calculation standards, and equations vary based on mud type and vendor. We also outline the increased complexity and decreased efficiency of the existing estimation process by focusing on two factors: first, equations are mostly embedded in a spreadsheet, which still requires manual interventions such as copying and editing values from large numbers of mud reports. Second, it can be time consuming, and the user needs hours-long training to comprehend the process. We then discuss the novel automated process where a suite of scripts written in open-source Python language runs via any open-source code editor. By using the popular Python library and DataFrame, tabular data from mud reports can be detected and pertinent values can be used as input for necessary calculation using the equations and charts already embedded in the scripts, which eventually generates salinity values in less than a minute. This project aims to deliver an automated solution to estimate borehole salinity. This methodology can be adopted by engineers on the rig and geoscientists in the office to calculate salinity values instantaneously without using any conversion chart or complicated equations whatsoever. In a case study using 20 samples from a typical mud vendor, we show that the new process is time saving and produces accurate borehole salinity values that are the same as values calculated using a manual technique. It is also a zero-cost process as open-source yet licensed software is used for estimation and needs little training for operation. The key innovative aspect of this project is to create a stepping-stone towards automation of day-to-day routine tasks that are being executed manually in the office and at the rig site. Existing salinity estimation has remained unchanged since early 2000 and calls for an update as the industry is taking aggressive steps towards automation. Borehole salinity automation is a first of its kind and its successful establishment will encourage more automation of similar calculation-based workflows.
Jalbout, Mohammad Muhab (ADNOC Onshore) | Al Hai, Ahmed (ADNOC Onshore) | Chammout, Omar (ADNOC Onshore) | Al-Rahma, Rahma (ADNOC Onshore) | Al Benali, Khaleefa Mohamed (ADNOC Onshore) | Al Blooshi, Saif (ADNOC Onshore) | El Bagoury, Ahmed (ADNOC Onshore) | Dubey, Anurag (Schlumberger) | Siddique, Ashique (Schlumberger)
Abstract Digital transformation has been proven to yield commercial success in the oil and gas industry with several reported advantages of value creation and business empowerment. The paper demonstrates the implementation of a breakthrough technology and ideology to steer rig operations in onshore locations in Abu Dhabi, by adopting unified Real Time Operations Center (RTOC) concept. The technology has enabled proactive evaluation of rig operations, integrated different stakeholders in one platform, and supported the decision-making process while providing additional opportunities for young engineers onsite. The unified RTOC technology approach is distinguished by empowering collaboration across functional departments. It enables higher levels of coordination of daily rig operations by converging processed and unprocessed information sources such as Technological Systems, Drilling Data Management Systems, Analytics, and Geomatics. Specifically for this exercise, the approach benefits are maximized by adopting a new concept to supervise rig operations remotely. The young drilling supervisors are settled to work on rig site, while senior drilling supervisors supports them from the office. One senior drilling supervisor can support 3 rigs at a time, covering exactly all major roles and responsibilities as if he/she is available physically onsite. The wells are monitored thoroughly with RTOC's platforms, associated risks are categorized, and several analytics were performed based on real-time data. CCTV integration with 5G technology braced the concept of monitoring the risky areas at the rig site with seamless footage. The CCTV integration was a step transformation for the proof of concept.
Krikor, Ara (ADNOC Offshore) | Bimastianto, Paulinus Abhyudaya (ADNOC Offshore) | Khambete, Shreepad Purushottam (ADNOC Offshore) | Cotten, Michael Bradley (ADNOC Offshore) | Toader, Lucian (ADNOC Offshore) | Landaeta Rivas, Fernando Jose (ADNOC Offshore) | Duivala, Shahid Yakubbhai (ADNOC Offshore) | Mughal, Muhammad Idrees (ADNOC Offshore) | Al Ameri, Suhail Mohammed (ADNOC Offshore) | AlMarzooqi, Adel AbdulRahman (ADNOC Offshore) | Chevallier, Bertrand (SLB) | Vallet, Laurent François (SLB) | Ullah, Nadeem Hidayat (SLB) | Qadir, Ahsan (SLB) | Al Khufash, Hassan Walid (SLB) | Shareef, Raneef Mohamed (SLB) | Ul Islam, Muhammad Ashar (SLB)
Abstract Digital Twin has become pillar of Oil and Gas industry. Previously, there was no solution / tool available to detect early bit failure, therefore Real Time Operations Centre (RTOC) team decided to develop and implement Mechanical Specific Energy (MSE) Ratio in real time to detect drilling dysfunctions and consequently prevent Non-Productive Time (NPT). The paper aims to demonstrate how MSE ratio helps to enhance the performance efficiency in real time while drilling operation. RTOC aggregates data from all the operational Rigs in real time and digital twin solution was developed to compute MSE Ratio in real time from downhole and surface MSE. Automated Machine Learning workflows compute downhole Weight on Bit and downhole Torque to compute downhole MSE. Surface MSE is automatically computed based on surface parameters. Output is filtered with Machine Learning Rig State workflow to avoid any false computation. The algorithmic outputs are calculated in time dataset and then converted to depth-based data in real time. Trend analysis of outputs will help to identify inefficiency and take decision on time. The Dynamic Solution can be used as smart drilling decision tool to detect bit performance abnormality and to enhance the efficiency for drilling operation. Trend of MSE Ratio output has helped to identify the bit failure in real time which further paves the way to decide bit trip and optimize the performance of the well. Case Study will demonstrate where trend of MSE ratio reached below the defined baseline and provided alert for potential bit failure. Bit trip was performed and based on bit dull grading, it was decided to run with new bit. MSE ratio observed on the new bit reached back to normal trend as per defined baseline. New bit was able to drill and complete the section within the plan. This tool has been implemented successfully on all the operational Rigs to monitor performance in real time and can help to take decisions to safeguarding and optimize the performance of the sections and well. Trend analysis of MSE Ratio along with other parameters can help to detect inefficiency and optimize rate of penetration (ROP) in real time. This innovative approach of using MSE Ratio can help to build new digital twin solutions and enhance utilization of MSE output. Machine Learning workflows leverages the objective of digital drilling transformation and to optimize drilling efficiency in real time. Output helps to improve performance and prevent unwanted events. Solution can be further enhanced to detect other drilling dysfunctions and define efficiency roadmap with the combination of Drilling Strength.
Hussain, M. Q. (ADNOC Onshore) | ALRashdi, A. A. (ADNOC Onshore) | ELMahdy, M. M. (ADNOC Onshore) | Mwansa, P. L. (ADNOC Onshore) | Amorocho, A. (ADNOC Onshore) | Ibrahim, A. M. (ADNOC Onshore) | Naga, H. (Weatherford) | Kaddoura, I. (Weatherford)
Abstract Weak formations which require isolation from elevated hydrostatic pressures during cementing operations have always been a challenge in the oil and gas industry. This paper will discuss the impact of deploying V0 Multi-Stage Cementing tool in terms of cement quality, well integrity and cost optimization. The losses experienced throughout the extended 9-5/8" casing strings resulted in reduction of the cement quality exposing the full well integrity to higher risks. Meetings have been held between engineering, material, production optimization and operation teams to evaluate the current performance and identify methods for improvement. V0 Multistage cementing tool was introduced as a unique solution which would assure reaching expected well integrity, overcoming hydrostatic pressure challenges, and eliminating risks of poor cement quality in the corrosive environment gas well applications. V0 Multistage cement tool has been successfully deployed for cases where elevated hydrostatic pressure was considered an issue, showing success in providing the required cement quality. Alternative methods to provide similar quality would be Liner hanger system followed by a tie back which would involve more associated cost, rig time and equipment. Wells with high differential pressures due to fluid losses have been successfully resolved avoiding risks of performing single stage cementing, compromising zonal integrity of weaker formations and poor cement quality. Qualified V0 Multistage cementing tool as per (ISO) 14310 V0 standard has been deployed, where gas-tight mechanical packer has enabled more reliable multistage cementing jobs for deep gas applications which ensured consistent and reliable gas-tight well integrity. V0 Multistage tool was considered an economical solution reducing the cost by 70% compared to alternative solutions, reducing average of 3 rig days. The paper will introduce the optimum economic solution for recurrent cementing challenges in both onshore and offshore operations. Utilizing latest technologies to retain wellbore integrity, eliminate unnecessary costs and reduce rig time.
Nunez, Ygnacio (ADNOC Onshore, UAE) | Al Nuaimi, Mouza Ali (ADNOC Onshore, UAE) | Adene, Olawole (ADNOC Onshore, UAE) | Al Hammadi, Aref (ADNOC Onshore, UAE) | Ruiz, Fernando (ADNOC Onshore, UAE) | Al Hamlawi, Imad (ADNOC Upstream, UAE) | Escorcia, Alvaro (ADNOC Upstream, UAE) | Baptista, Luis (ADNOC Upstream, UAE) | Labbassen, Nabila (ADNOC Upstream, UAE) | Radovanovic, Anna (Coreall, Norway) | Berger, Per Erik (Coreall, Norway) | Mätzel, Arne (Coreall, Norway)
Abstract The search for oil dates to the 1850s, and, since continuous overtime improvements and enhancements to the available technologies have been introduced. However, the quest for continuous improvements is directly related to the advantages and ease of exploitation of this nature given resource. Currently, concepts of formation evaluation, which is the analysis of subsurface formation characteristics, such as lithology, porosity, permeability, and saturation, are acquired by methods such as wireline well logging, real-time logging while drilling and core analysis. The advantage of core analysis (coring) fully leans on the ability to retrieve cores as close as possible to the actual reservoir's properties, hence porosity and permeability can be more precisely evaluated. The main aim of this project is to prove that it is possible to core and log at the same time, thus saving time and increasing the accuracy of the coring points. First phase of this trial as technological innovation is an Advanced Coring System (ACS), which cuts the core while logging, and contemplates gamma ray and resistivity sensors within the core Bottom Hole Assembly (BHA) itself, close to the core head. Due to the presence of electronic components within the coring equipment, the core diameter was limited to a 3 in. OD core. The first trial was done on a middle east onshore field during Q3 of 2022. The main objective was to ensure that reservoir information (gamma ray, inclination, vibration, temperature) was being acquired real time while using the Intelligent Coring System (ICS) to enable retrieval and interpretation of downhole data. The coring BHA was composed by a coring head, the Logging While Coring (LWC) tool, wired outer barrels, wired spacers and stabilizers, a drop ball sub, and an MWD module. The coring assembly was successful at cutting and recovering the target core interval with good performance, comparable to standard coring BHA, however, the main objective of the trial, the LWC was not achieved. The MWD experienced malfunctions, hence no real-time gamma ray data was transmitted to surface. After POOH the assembly was laid down, and preliminary investigation at the rig site showed the showed fluid invasion of the electronics components, impairing the memory data retrieval. As a last resort, the memory board was disassembled and taken to the manufacturer's laboratory to attempt data recovery. Unfortunately, the board was damaged beyond repair due to the fluid ingress and the memory data was unretrievable. The ICS is a novel technology, potentially disruptive of the way coring is done today: A coring system, which combines coring and real-time formation evaluation. A second innovative technology is under development, is the Downhole Convertible Drill Bit a system that allows downhole conversion between coring and drilling modes, thus saving several round trips. This system is to be tested in field applications.
Abstract An oilfield service company was awarded the scope by an operator in the North Sea to recover three slots from an existing offshore platform and redrill the HPHT wells to tap into unreached reservoir resources on a gas field. This paper covers the holistic approach of analysing the slot recovery operations strategy, plug and abandon the original wellbore, and how to avoid tunnel vision in the decision-making process to achieve the goals. Cut and pull operations have one of the highest financial impacts on slot recovery and can lead to loss of the well in unfortunate circumstances. After slot recovery operations, including the cutting and milling of the 10-3/4″ × 10″ casing, the 13-3/8″ casing failed the pressure test. The incident triggered a Cause Analysis Tree Diagram of the well conditions that led to the discovery of a hole in the 13-3/8″ casing. The investigation highlighted the tunnel vision of the decision-making process where ‘stop points’ were bypassed or not efficiently identified, contributing to operational delays and potential loss of the wellbore. The investigation concluded that insufficient information on the well was obtained during the planning phase and the financial decision tree analysis was incorrectly defined to proceed with the preparation of the contingency plans. In this process, all existing logs were re-evaluated to identify the solids behind casing, ovality, centralization, and casing-on-casing contact points. The original plan was to cut and pull the casing and then mill ~374ft of casing, with a shallow sidetrack option as contingency. However, during the execution, due to height of the top of solids encountered behind the casing, it was required to start milling from a shallower depth, with a total of ~ 1,500 ft of casing to be milled. At this stage in the operations, a fishbone diagram should have been created to perform a detailed analysis of the technical risks and cost impacts and to decide whether to continue milling or to proceed with the contingency option to sidetrack from a shallower depth. However due to peer pressure, tunnel vision goal seeking (Gasaway, n.d.), and phycological safety the multi-factor decision ‘stop points’ were not considered leading to an expensive, lengthy, and unsuccessful operations. This paper summarizes the decisions and ‘stop points’ in the process of slot recovery operations and highlights the potential outcomes of incorrect technical risks and cost analysis. Further reviewing the utilization of the engineering analysis, and economical aspects through preparation of a fishbone diagram to manage stakeholders’ expectation on upfront commitment to continue with challenging slot recovery operations on a major decision-making point. The example and process provided in this paper will benefit the industry by helping to recognize a ‘stop points’ in the operations, highlighting the risks of having catastrophic event.
Abstract Well was drilled in Al Nouf field with the objective to support the pressure sustainability of multiple producer wells across SH formation based on MRC / ERD approach. This paper presents the challenges faced in planning and drilling of subject well with departure of above 15,000ft and soft landed above the reservoir and later drilled 8.5" hole section to total measured depth of above 37,605ft (11.642 km) with having horizontal section of above 20,000ft with directional difficulty index (DDI) of 7.541 using heavy casing design. Planning of this well commenced by meetings and collaboration with subsurface operation and reservoir team with the common objective of drilling a well of over 15,000 ft of departure and keep the well smooth for drilling long eMRC horizontal section. New technology was used with a common objective to achieve the goal and make trajectory smooth to provide max chance for lower completion to reach the max TD of the well. All the associated risks were highlighted and mitigated by proper planning and engineering analysis such as trajectory, collision risks, BHA, hydraulics and casing design. This eMRC/ERD well of above 37,605ft MD (4.12 ERD H:V ratio) is the first well in the region to successfully completed even with directional difficulty index (DDI) of 7.541 This paper will explain the innovative and novel approach of mitigating the challenges faced while drilling a complex well of 15,000ft departure and have an extended horizontal section of over 20,000ft with 8.5" drainage. A few challenges like drilling across the faults across horizontal hole section and collision risk at deviated and horizontal section were major concern but successfully catered with advanced engineering analysis and innovative technologies like torque reducer, turbo caser and swivel master etc. Results from this well have proven that having lower completion in MRC / ERD wells have significantly improved the well accessibility and well performance and enhanced the reservoir management and significantly reduced the field development cost. This paper summarizes the practice and technology used to successfully drill the MRC / ERD well in artificial island. The challenges and its mitigation explained in this paper will support the idea to plan and drill the well beyond the reservoir boundaries to gather more data and to enhance more production. Also, this paper will provide novel approach of having lower completion in MRC/ERD wells which helps to attain more control on injectivity / productivity of reservoir because of proper isolation by swell packers and have maximum well accessibility across ERD horizontal section.