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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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.
Abstract Drilling operations take place in an environment where high and low pressures are challenges. Both can cause delays, increased expenses, and even failure if they occur unexpectedly. Operators are increasingly equipping themselves against the repercussions of pressure-related surprises by employing strategies that are distinct from those previously employed. Managed pressure drilling (MPD) is one such break from tradition. The drilling margin, also known as the pore-pressure-fracture gradient window, is the pressure range between pore pressure and fracture formation pressure. Operators must set casing and begin drilling the following, smaller hole size if the equivalent circulation density (ECD) goes outside these boundaries at any stage. Overbalanced drilling (OBD) is the process of maintaining a borehole pressure that is higher than the pore pressure gradient. Drilling is challenging in some operations due to the restricted operating window between pore pressure and fracture pressure. An oil field in North Africa is the subject of a feasibility study for controlled pressure drilling. Mud returns were lost while drilling in an unconsolidated formation in prior wells drilled in this field. This project effort solves this issue by applying surface back pressure to Managed Pressure Drilling technology in this field. The methodology used in this study is based on employing a real-time model to optimize (ECD) values and a drilling simulator to compare drilling operation pressures. To compare the pressures with the required back pressure, the model estimates the annular pressure drop and corresponding circulation density. The goal of this project is to employ Managed Pressure Drilling calculations to drill the well, optimize the mud weights used to drill the well, reduce the number of casing strings, and avoid losing drilling fluid. As a result of this technique, the MPD optimization will be used to drill the well in a safer and more cost-effective manner while avoiding drilling problems, lowering the Non-Productive Time (NPT).
Hassan, Azza El (Drilling, ADNOC, Abu Dhabi, UAE) | Abdelatif, Mohamed Samir (Drilling, ADNOC, Abu Dhabi, UAE) | Hamidzada, Ahmedagha (Drilling, ADNOC, Abu Dhabi, UAE) | Andrews, Kerron (Drilling, ADNOC, Abu Dhabi, UAE) | Toki, Takahiro (Drilling, ADNOC, Abu Dhabi, UAE)
Abstract In an Offshore field, off the coast of Abu Dhabi, well integrity objectives are becoming more difficult to achieve as open hole sections become deeper, laterally longer and more highly deviated. In this mature field, one of the main challenges of well construction is successfully cementing long production-casing strings covering multiple reservoirs across the 8½-in sections. This paper describes some of the techniques and best practices that were applied on these wells to achieve the required zonal isolation. Achieving zonal isolation across multiple reservoirs through a single or multi-lateral configuration is a major challenge in this field. The reservoir formation is porous and requires a special gas tight design or impermeable cement system. Inadequate hole cleaning due to poor standoff attributed to complex well design is another main limitation, resulting in insufficient mud removal leading to an uneven cement distribution around the casing. Additionally multiple pressure-testing cycles are required post cement-setting and during the completion phase, a practice that can destabilize the cement system causing it to fail. Moreover, controlling loss circulation while running or after landing casing is another challenge in this field. To overcome these challenges a series of customized improvements were applied subsequently through continuous improvement and implementing lessons learnt from previous operations. The elements of this approach included introducing higher density cement systems to cover the horizontal sections, while retaining the ECD within the required margins. Another element utilized was that of two cement slurries; Lead and tail, which were designed to achieve controlled ECD. An additional element which was also implemented addressed enhancing the flexible expandable gas tight slurry by adding Latex to achieve a fit for purpose solution. The last element of this strategy included improving hole cleaning and mud removal efficiency by optimizing spacer design and volumes in addition to the loss circulation additives in the spacer systems. Throughout the operation, the cement jobs were executed successfully with no losses. Cement jobs were evaluated through running job design simulation Vs execution parameters comparison. The approach resulted in substantial improvement on log responses. Additionally, after implementing the approach, logs were compared to offset wells from the same field to track the improvement done. The paper reviews enhanced practices implemented to overcome challenges faced during well cementing. Being able to find a solution to this complex problem, delivering a comprehensive cement quality, and improving cementing integrity on these wells resulted in expanding this approach to the rest of the fields. The improvement measures that were developed are now being adopted across all jobs to yield a similar outcome.
Abstract This paper illustrates the methodology and the challenges faced from the planning to execution phases while implementing digital solutions to overcome the drilling operational challenges. In a candidate well, the package with real-time downhole performance measurement (RT-DPM) software, an automated rheometer, and an automatic data graphic visualization interphase, provided visibility into downhole conditions. This was used to predict potential problems and reduce the likelihood of the common issues related to the drilling operation. The RT-DPM software was successfully implemented in a well to reduce the likelihood of stuck pipe incidents and hole cleaning issues. The implementation has enabled real-time monitoring of annular pressure, equivalent circulating density (ECD), equivalent static density, pipe eccentricity, swab, and surge pressure, allowing optimization of the operation time. The lateral section has been drilled successfully with high overbalance without any operational issues. While drilling the production section with several operational challenges, such as losses/gains environment, and high overbalanced formation with a high probability of potential differential stuck, the well was completed successfully, maintaining a good hole cleaning at any point in the annular space of a well. The visibility of the downhole parameters enhanced the rate of penetration (ROP) and optimized the drilling time. A wiper trip was eliminated due to the excellent hole cleaning and the minimal cutting bed generated. Planning started taking into consideration the key point, which was identified as: the close contact points of the pipe to take the extra measurements to avoid such differential sticking in a high overbalanced formation. The overall results were exceptional from the broomstick, showing the parameters were following the ideal trend with no indications of any tight spots. With a steady pick-up weight, slack-off weight, and break-over torque, the hole was identified to be in very good condition. The oil and gas industry is moving to the automation and machine learning methods, and in this paper we will be presenting the methodology and the challenges faced from the planning to execution phases, while implementing automated digital solutions to overcome the drilling operational challenges.
Kassim, M Shahril B Ahmad (PETRONAS Carigali Sdn Bhd, Kuala Lumpur, Malaysia) | Marzuki, Izral Izarruddin B (PETRONAS Carigali Sdn Bhd, Kuala Lumpur, Malaysia) | Azid, A. Aznan Azwan Bin Abd (PETRONAS Carigali Sdn Bhd, Kuala Lumpur, Malaysia) | Rajan, S. Teaga (PETRONAS Carigali Sdn Bhd, Kuala Lumpur, Malaysia) | Fadzil, M Redha B (PETRONAS Carigali Sdn Bhd, Kuala Lumpur, Malaysia) | Motaei, E. (PETRONAS Carigali Sdn Bhd, Kuala Lumpur, Malaysia) | Ong, L. W. (PETRONAS Carigali Sdn Bhd, Kuala Lumpur, Malaysia) | Jaua, R. D. P. (PETRONAS Carigali Sdn Bhd, Kuala Lumpur, Malaysia) | Jamaldin, Fadzril Syafiq B (PETRONAS Carigali Sdn Bhd, Kuala Lumpur, Malaysia) | Ting, S. (SLB, Kuala Lumpur, Malaysia) | Daungkaew, S. (SLB, Kuala Lumpur, Malaysia) | Gisolf, A. (SLB, Kuala Lumpur, Malaysia) | Chen, L. (SLB, Kuala Lumpur, Malaysia) | Ling, D. (SLB, Kuala Lumpur, Malaysia) | Hademi, N. (SLB, Kuala Lumpur, Malaysia) | Khunaworawet, T. (SLB, Kuala Lumpur, Malaysia) | Nandakumal, R. (SLB, Kuala Lumpur, Malaysia) | Kossayev, Y. (SLB, Kuala Lumpur, Malaysia) | Wattanapornmongkol, S. (SLB, Kuala Lumpur, Malaysia)
Abstract The objective of this paper is to present well control challenges, and results of utilizing wellbore dynamic simulation to achieve safer formation tester (FT) sampling and deep transient tests (DTT) operations. Insight will be provided based on the first implementation in a Southeast-Asia offshore well, with focus on pre-job simulation that is validated with measured data to help improve understanding of gas/hydrocarbon interaction with wellbore mud during and after FT pump-out operations. FT involves obtaining formation pressure, pressure transients, and downhole fluid samples, and the latest DTT technology enables larger gas/hydrocarbon volumes to be pumped into the wellbore which requires a comprehensive understanding of the processes involved. Wellbore dynamics accurately predicts the interactions between downhole pumped hydrocarbon and drilling fluid using a dynamic multiphase flow simulator. For the sampling operation, a maximum allowable downhole gas volume is evaluated prior to operation and simulations are compared to surface gas observation obtained during a wiper trip (mud circulation). During DTT operations, pumped formation fluids are routed to a circulating sub, where they are mixed with circulated mud and the mixed fluids are simultaneously carried to surface. Downhole wellbore pressure measurements are sent to a real time cloud-based dashboard and compared with simulations. The ability to weigh measurements against simulations creates a comprehensive understanding of well control scenarios and provides a much safer execution of FT operations than conventional methods. For wireline FT operation, post job comparison showed that the simulation matched well with surface observations during the wiper trip. The simulator accurately predicted the surface free gas arrival compared to mud-gas logging measurements, which confirmed that gas stayed dissolved in the Synthetic Based Mud (SBM) downhole without migrating upwards. For DTT, wellbore pressure measurements were sent in real time to a cloud-based dashboard and are compared to simulations and simulations could be quickly re-run to account for changes in observed formation fluid, downhole flowrates or mud circulation rates. The FT and DTT operations were conducted successfully and safely and in both cases the measured data agreed well with the simulations. With the accurate wellbore dynamics simulator, changes in drilling fluid design, circulating rates, hydrocarbon composition, downhole pump rates, and pump duration for various FT design sequences are quantified, and the downhole well pressure, free-gas distribution along the well geometry, and gas rates on surface can be predicted. This insight provides more flexibility and understanding to plan advanced FT operations and enables larger volumes of hydrocarbon to be pumped downhole. Furthermore, adopting an advanced pressure transient testing method like DTT also aligns with the industrial effort of reducing carbon dioxide emission footprint.
Abbood, Husam Raad (Basra oil company, Basra, Iraq) | Khalil, Dr.Ethar (Petroleum Engineering, University of Basra, Basra, Iraq) | Miftah, Karrar Riyad (Petroleum Engineering, University of Basra, Basra, Iraq) | Khalaf, Amgad Hamad (Petroleum Engineering, University of Basra, Basra, Iraq) | Abdullah, Ibrahim Salim (Petroleum Engineering, University of Basra, Basra, Iraq) | Khudhaier, Muhammed Adnan (Petroleum Engineering, University of Basra, Basra, Iraq) | Jaber, Ali Hassan (Petroleum Engineering, University of Basra, Basra, Iraq) | Hamad, Zamzam Neama (Petroleum Engineering, University of Basra, Basra, Iraq)
Abstract The oil and gas industry is witnessing an increasing demand for more cost-effective well design and operations. Thus, the scope of the operator company's planned new processing capacity aims to attain a competitive cost and schedule. In this work, slim versus fat casing designs are evaluated in price and technical challenges, including removing rig/skidding, drilling, and ensuring well suspension. Data from ten (five slim design and five fat design) wells in southern Iraq was quantitatively analyzed. Attaining the project's target requires that the well be drilled as a deviated well (S-type). The analysis includes the cost of CSG, lost circulation, lost curing, lost circulation materials, volume of the cement plugs to cure losses, non-productive time, stuck pipe and differential sticking, and cement bond quality. Moreover, a cost analysis is conducted by considering all of a project's relevant factors—including economic and technical considerations—to ascertain the likelihood of completing the project. The finding emerged that the amount of lost mud and the average cost of addressing losses were higher in slim than fat designs. The slim design is associated with higher volumes of cement plugs for curing losses than the fat design. As per NPT analysis, the time required to fix losses emanating from slim design was 62% higher than fat design. A critical observation emerged from the study that while differential sticking failed to occur in both designs, stuck pipes happened in some of both designs. The cost analysis of slim and fat designs focused on the cost of drilling, CSG, wellhead, diesel, and fueling is also done. The total cost of the fat design amounted to approximately 53.67%, while the total cost of the slim design was about 46.33%. This made the slim design's cost savings ratio of roughly 7.34%. Meanwhile, given that similar issues may occur in the proposed well design, the following measures have been isolated to help tackle such problems. (1) Optimize mud design to inhibit Tanuma formation Clay swelling issues (2) Reduce OH time to avoid Tanuma's time-dependent clay swelling. (3) Reduce the inclination across Tanuma to 20 degrees. Finally, this paper describes how two casing designs are successfully engineered and executed and serves as a guide for selecting proper candidates for this design. Also, it is an operational guide for two casing designs, slim and fat, to ensure that these challenging long open holes will be successfully and economically drilled while minimizing risks and ensuring compliance with the well delivery process.
Abstract The deep shale gas reservoir are high formation temperature and pore pressure in Sichuan Basin. Due to the unclear geomechanical characteristics of the reservoir, a large number of accidents occurred during the drilling operation. At the same time, the wellbore instability and frequent adjustment trajectory cause long drilling cycle, low drilling efficiency, and high drilling operation cost. To solve the above problems, the drilling mud weight is optimized based on the three-dimensional geomechanical research and by establishing the pore pressure, collapse pressure and fracture pressure (leakage pressure) models. The key technology of reducing drilling mud weight are used to significantly reduce the drilling mud loss. Field application shows that the mud weight is reduced from 2.15 g/cm to 1.87 g/cm, the average ROP increased by 44.1% from 8.4 m/h to 12.1 m/h, the average drilling operation cycle decreased by 40.7% from 54.2 days to 32.1 days, and the drilling performance and efficiency are significantly improved. The fine 3D geomechanical modeling technology has great promotion and reference significance for the performance and efficiency improvement of the deep shale gas horizontal well drilling operation in China.
Abstract The Mumbai High field in Western offshore of India presents major challenges to both drilling and liner running operations, because of reservoir being depleted and severe lost circulation conditions. Thus Liner while drilling, a new technology was deployed as a pilot Project to drill in these troublesome carbonate reservoir. The operator had previously experienced severe losses in the zone leading to big loss of rig days and damage to Reservoir due to LCM (Loss Circulation Materials) Pills. The liner while drilling service is a sustainable technology which combines 4.75in rotary steerable system BHA (Bottom Hole Assembly) with various logging tools, 8.75in hole opener/reamer, a mud motor, and a 7in liner with 8.5in reamer bit to help overcome the challenges while drilling in zones with low formation pressure and unstable formations. Running the liner while drilling helps maintain wellbore stability and reduces open hole exposure. It is also beneficial in reducing the time required by eliminating extra trips as the liner is installed at Target Depth in the first run. It is important to understand that Drilling with a mud motor and low RPM from surface is stressing the formation much less than conventional Rotary steerable BHA. Losses were contained with special mud additives. Plastering & smearing effect across the well bore added value in curing the Losses. This Technology Reduced formation damage by avoiding repeated LCM pills. Post Drilling, the inner string was Pulled out of hole leaving the liner at bottom which was later cemented with Cement Retainer. The technology proved to be Sustainable and with reduced HSE risk for the operator. The Paper will discuss in detail about the field of application, Prejob planning for Liner while Drilling Job, Onsite Execution and Successful completion of the well. This technology Successfully drilled, lowered, and Cemented 7in Liner at Target Depth saving rig time for the operator.
Abstract To overcome the challenges of drilling depleted reservoirs, a new technology was needed as part of a cost-effective solution. An innovation campaign was facilitated by a major oil company R&T (research and technology) department in the North Sea to identify concepts enabling high depletion in drilling through reservoirs. Several concepts were evaluated, and a packer in the drillstring was defined as a necessity by the major oil company. Drilling through depleted reservoirs has become more and more common in operations run by both oil operators and drilling companies, in fields that have matured. Drilling these wells introduces an increased risk for crossflow and losses and a series of mitigating actions have been put in place to obtain an acceptable risk level. This paper will focus on describing the steps taken to develop a packer that provides a seal between the drillpipe and the production casing, being part of the drilling BHA and spaced out to stay inside the casing. It's large bore through allows high flow rates and deployment of intervention tools through it. By setting the packer, it becomes a qualified V3-barrier, validated as per ISO14310 and/or API11D1, enabling the operator to cement and sidetrack efficiently, saving additional trips and rig time. This successful technology cooperation will help oil operators and drilling companies to expand its capabilities for drilling depleted and complex reservoirs and further increase the overall recovery factor for its mature fields. Rising to the challenge, means to improve the confidence in drilling with limited drilling window and avoid uncontrolled risks by using a Drillstring Annulus Sealing Packer that when set, provides a seal between the drillpipe and the casing, the packer activation is meant to be the last option in a series of mitigating measures as the wellbore will be abandoned if activated.
Ye, Yuguang (China University of Petroleum-Beijing, Beijing, China) | Fan, Honghai (China University of Petroleum-Beijing, Beijing, China) | Liu, Yuhan (CNPC Engineering Technology Research and Development Company Limited, Beijing, China) | Tao, Zhenyu (China University of Petroleum-Beijing, Beijing, China) | Diao, Haoyu (China University of Petroleum-Beijing, Beijing, China) | Zhou, Fei (China University of Petroleum-Beijing, Beijing, China)
Abstract With the gradual progress of drilling to the deep layer, the formation conditions become more and more complex. The safe density window of drilling fluid is narrow, and well kick and overflow occur frequently. Aiming at this problem, this paper proposes an overflow evaluation index - overflow formation energy. From the perspective of energy analysis, overflow is regarded as the process of formation fluid doing work on the wellbore, and the power of overflow work can reflect the strength of overflow, so this power is defined as the overflow formation energy. Based on the model established in this paper, the effects of different types of overflow fluid, invasion rate of overflow fluid, drilling fluid density and formation pressure coefficient on overflow formation energy are analyzed. The overflow formation energy of gas is the highest. As the invasion rate of overflow fluid increases, the energy of overflow formation gradually increases. The data of 7 overflow wells are analyzed, and the corresponding overflow formation energy is calculated. It is found that the throttling circulating well killing method is more appropriate when the overflow formation energy is small. The overflow formation energy can quickly evaluate the overflow situation, provide theoretical basis for well control operation, and reduce the probability of well control operation risk.