The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Moradi, Mojtaba (Tendeka) | García, Willy (Petrotal Peru) | Amado, Percy Martin (Petrotal Peru) | Konopczynski, Michael Robert (Tendeka)
Abstract Growing energy demand heightened by climate change challenges has seen the oil and gas industry tightly embrace smarter and more sustainable technologies. The motivation is to quickly grasp net-zero targets, while safely optimising oil-gas production. By its nature, the industry has the ingenuity to eliminate unnecessary carbon emissions. However, traditional development plans relied on the use of wells with minimal or no emphasis on the well completion in terms of optimum deliverability. This would produce a mixture of oil and excessive unwanted fluids such as water and/or gas which requires costly energy-intensive processes. Although the process has been optimized to some extent and often re-injects these unwanted fluids back to the reservoir, there has been not enough attention to the environmental impacts as these repetitive treatment processes of the fluids results in discharging excessive and unnecessary Greenhouse Gas (GHG) into the atmosphere. The issue is now widely recognized to be one of the industry challenges in its drive toward net-zero energy delivery. A case study of a heavy crude oil field with a strong water drive, located in a natural reserve in the Marañon basin of the Peruvian Amazon is presented. Here, the implementation of autonomous inflow control devices (AICDs) technology, through a knowledge management process, has made it possible to significantly reduce the volumes of water produced, which are reinjected again, thus generating significant savings in fluid lifting, treatment and energy consumption associated with the operations in this field. The study introduces a workflow that uses a publicly available GHG footprint estimator to evaluate the carbon intensity of different oil and gas field development plans. The estimator predicts the amount of GHG emitted from any individual operation, process and treatment involved in a field development from exploration to delivery at the gate of a refinery. Having this calculation enables the operators to recognize the major GHG emitter operations and optimise the process toward net zero using new technologies, methods and/or workflows. The workflow has then been applied to the field located in the Peruvian Amazon to illustrate the significant impact of flow control technologies on the reduction of GHG emissions and achieving net-zero targets. For example, the amounts of carbon intensity, GHG emission and energy consumption from the field have been estimated to been reduced by up to 56%, 64% and 78% respectively with AICD completions compared to a case of non-AICD completion such as stand-alone screen (SAS) was installed in the wells instead. This study provides the engineers with a workflow to quantify the impacts of the use of new technologies especially flow control devices. It also illustrates the significant role of flow control technologies in achieving net-zero production.
Abstract This paper describes how near real-time tracer data from the onsite tracer analysis enabled the operator in the Nova field to interactively optimize two well clean-ups to the rig. The tracers provided key information on the clean-up progress in different zones which enabled the operator to make informed and fast decisions to maximize well clean-up efficiency while minimising rig time and cost. Verification of well clean-up to increase zonal productivity and to eliminate the risk of damage to the surface production unit with minimum rig time is always a challenge during well start-up. The conventional wellbore clean-up practices are to monitor surface parameters including produced mud volume and basic sediment and water (BS&W) in the production fluids until a certain criterion for these parameters are met. However, this method cannot confirm that all the zones are cleaned up and are contributing to the production. Having the right monitoring technology to confirm well clean-up at the zonal level is therefore essential to successfully clean up the entire reservoir section. Inflow tracers with onsite analysis provide near real-time data on clean-up efficiency in different zones. Unique tracer molecules are embedded into the polymer systems and permanently installed in the lower completion. Oil and water tracers remain dormant until they come into contact with their target fluids. Once activated, the tracers are released into the target fluid for a certain designed life period and can be sampled when the well is opened. The collected samples can be analysed onsite or offsite at a laboratory. The onsite analysis can provide near real-time data and is preferred for a fast decision-making process such as during the clean-up to rig. The Nova drilling plan consisted of three oil producers (two horizontal and one slanted). The onsite tracer analysis with fast analysis turnaround time was used for the two horizontal wells. For the first horizontal well (X-3H), the tracer data results confirmed a strong heel clean-up efficiency from the very beginning and a weak toe clean-up efficiency. The middle and toe zone tracers appeared 8 and 12 hrs after opening the well respectively, therefore confirming oil contribution from all zones. Due to weak clean-up at the toe, the operator decided to prolong the clean-up at maximum drawdown to improve the clean-up of the toe section. For the second well (X-4 AHT2), the toe section exhibited effective clean-up from the very beginning while the heel zone showed a gradual clean-up and started to clean up 10 hrs after opening the well. Monitoring well performance at the zonal level without any intervention and in a cost-effective manner is a challenge, especially during the initial opening of the well to the rig. In this case, the inflow tracer technology was successfully utilized to provide near real-time validation of clean-up and flow contribution. This enabled the operator to understand his wells’ behaviour and make real-time decision to increase the clean-up efficiency and zonal productivity while efficiently using the rig time during the field development phase.
Completions News Advanced Diagnostics Aid Understanding at Hydraulic Fracturing Test Site 2 Multistage Acid Stimulation Uses Straddle Packer, Real-Time Telemetry SPE Energy Stream SPE Energy Stream is your go-to for watching thought leaders, subject-matter experts, and leading companies share their perspectives and technical solutions. View more on SPE Energy Stream Online Education Join industry experts as they explore solutions to real problems and discuss . SPE webinars are free to members courtesy of the SPE Foundation. Online Journals SPE Drilling & Completion features papers covering horizontal and directional drilling, drilling fluids, bit technology, sand control, perforating, cementing, well control, completions, and drilling operations. SPE Production & Operations includes papers on production operations, artificial lift, downhole equipment, formation damage control, multiphase flow, workovers, and stimulation.
Varma, Esha Narendra (ADNOC Onshore) | Ditzler, Theodore Jay (ADNOC Onshore) | Mwansa, Peter Levison (ADNOC Onshore) | Husien, Mohammad (ADNOC Onshore) | Bahrom, Abdul Raman Bin (ADNOC Onshore) | Saragi, Raymond (ADNOC Onshore) | Samahi, Musabbeh Khamis Al (ADNOC Onshore) | Shamsi, Juma Sulaiman Al (ADNOC Onshore) | Alshaigy, Ahmad Othman (ADNOC Onshore) | Gaurav, Anchit (Churchill Drilling Tools) | Abdelhalim, Khaled (Churchill Drilling Tools)
Abstract Extended reach drilling (ERD) can facilitate the development of untapped resources, reduce greenhouse gas emissions, surface congestion, and drilling costs. This ERD project with lower completion was started with an aim to lower well cost indicators including $/ft and $/bbl. Therefore, the challenge was to drill Slimhole ERD (6-1/8″ lateral) wells with water-based mud (WBM). WBM is more cost-effective, environmentally friendly, and less damaging to the reservoir than OBM (oil-based mud). The use of WBM instead of OBM can save $2MM per well. The major challenges in drilling Slimhole (6-1/8″ size) ERD well with lateral le include higher torque and failure to deploy lower completion due to high friction factors. The first pilot well was planned with a liner-less design considering the low friction factors required to drill 15,000′ of 6-1/8″ lateral hole and run the lower completion. The second pilot well was targeting a deeper and tighter reservoir zone with higher downhole temperatures. This involved drilling 12-1/4″ intermediate hole to the landing point with larger 5-1/2″ drill pipe. It enabled a push-pipe technique for drilling the lateral hole with improved weight transfer through the curved profile. The 6-1/8″ lateral hole was drilled with 4″ high-torque drill pipe, tandem high-flow circulating subs, and specially formulated drilling fluid lubricant. A conventional OBM system provides sufficient lubricity to reduce friction factors as low as 0.10. In this application, a low cost WBM system was made feasible by introducing stable high-temperature lubricant and unique hole cleaning practices. Following this successful achievement, the 5-year business plan has been revised to include 63 similar wells with a projected total savings of ~ $250MM. The Slimhole ERD project has demonstrated substantial value with a 35% reduction in CAPEX. The delivery of these two Slimhole ERD wells overturned conventional drilling and completion practices. The implemented project resulted in saving up to 35% of the well cost and saved 20 days per well compared to a conventional ERD well with 8-1/2″ hole and OBM. These two Slimhole ERD (15,000′ lateral) wells were drilled with a challenging Directional Difficulty Index (DDI) of 7.2. The wells were both completed successfully by running the 4-1/2″ lower completion to reach the total depth.
Abstract ADNOC onshore's reservoir development strategy has historically been to drill barefoot wells and perform interventions as production deteriorates. Barefoot wells increase flexibility, lower cost, and reduce operational risk, but unbalanced fluids influx, and early water/gas breakthrough may reduce oil recovery. Autonomous Inflow Control Valve (AICV) technology tackles these limitations while eliminating/reducing the associated risks/costs with other inflow control technologies. This paper presents a series of successful pilot workover interventions deployed in the UAE to revive wells and boost recovery. Successful execution of four UAE onshore assets (two gas shut-off, two water shut-off applications) as part of a pilot to assess and approve the AICV technology initiated a new paradigm in restoring oil recovery and production accessibility of inactive and/or low performing wells. Well selection required screening, robust simulation modelling, and assessments of accessibility and downhole integrity. Stringent reviews of required rig operations, lower completion (LC) designs, and various completion components were conducted. The integrated work between various business unit domains helped create new workflow chains and resulted in the implementation of several best practices in planning, design, execution, and evaluation. LC configurations were optimized by T&D modelling, time lapsed simulations, and the use of reservoir data obtained during rig interventions. The design challenges encountered with the limitation on number/type of isolation packers, segmentation, type of shoe, use of a light workover rig, risk mitigations, field execution, well flowback, best practices, and lessons learned are all addressed highlighting how a shut-in well was revived, and other wells observed drastic improvements in production performance. The impact this has on lowering carbon emissions and associated costs by reducing the need for electricity for lifting, handling, treatment, storage, disposal of water and potential venting/flaring gas and risky interventions is demonstrated. Standard practices and boundaries were successfully stretched to truly show the value of the AICV technology; more than double the usual operator standard of isolation packers were deployed in one well after thorough planning, risk evaluations, and effective collaboration. All four wells successfully reached TD without additional complexities or QHSE incidents. Preliminary assessments for the first well, for example, indicated GOR almost halved while enabling oil production at more than double the pre-shut-in rates. Substantial reductions in carbon emissions and costs are expected over the life of the well. The paper introduces the first ever wells installed with AICVs in the UAE and documents newly established best practices for AICV planning and execution. With hundreds of similar applications globally, the opportunity to revive shut-in wells, reduce unwanted fluid production, and improve ultimate recovery, while lowering costs and carbon emissions is evident. The operator plans to further deploy the AICV across its applicable assets to find hidden barrels from existing reservoirs, and to proactively manage their reservoirs in new wells.
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.
Samir, N. (ADNOC) | Raju, P. Sumish (ADNOC) | Abrejo, M. (ADNOC Onshore) | Shbair, A. (ADNOC Onshore) | Fahd, O. (Halliburton) | Al Jabery, R. (ADNOC) | Al Reyami, M. (ADNOC) | Sarhan, M. M. (ADNOC) | Bin Shamlan, A. Mubarak (ADNOC) | Alhammadi, M. (ADNOC Onshore) | Al Shehhi, S. (ADNOC Onshore) | Khaled, M. (ADNOC Onshore) | Soufi, A. (ADNOC Onshore) | Alsaadi, S. A. (ADNOC E&P) | Bethancourt, R. (ADNOC) | Jalbout, M. (ADNOC Onshore) | Ahmed, I. (ADNOC Onshore)
The smart completions installation in open hole allows maximize the oil production recovery from multiple reservoirs and have inflow control management. The deployment in open holes demands a lot of challenges due to the number of delicate equipment installation, extensive integrity tests and associated stuck pipe risks in open hole, in addition to the smooth wellbore geometry required to ensure deployment. For the first longest open hole mono-bore smart completion installation, a 6.125 inches horizontal hole section was planned and optimized by the application of advanced drilling engineering for torque, drag and Geosteering well placement to minimize the doglegs in the horizontal section. Best operational practices along with drift run and drilling fluid optimization are part of the engineering design that enabled the success and smooth running of the smart completion to total depth. This mono-bore open hole completion will revolutionize the typical well design and drilling operations since it gives maximum contact with the reservoir and full control over the flow that can allows to close path for any unwanted fluid without for Coil Tubing intervention.
Omer, Farhan (SLB, Houston, Texas, United States) | Rudic, Aleksandar (SLB, Houston, Texas, United States) | Song, Lijun (SLB, Houston, Texas, United States) | Gupta, Susheel Kumar (SLB, Houston, Texas, United States) | Kamath, Raghuram (SLB, Houston, Texas, United States)
Summary This paper presents the effective use of computational fluid dynamics (CFD)-based erosion modeling to optimize the development of gravel-pack completion equipment, in this case a shunt tube isolation valve (STIV), which enables total zonal isolation following gravel-packing operations. A novel erosion- and debris-resistant approach to the design of the STIV was developed. The product development methodology incorporated the use of an iterative CFD erosion model to quantify the erosion rates on a proposed novel STIV flow conduit for gravel packing. The erosion model simulated a typical gravel-pack treatment using a multiphase fluid model of carrier fluid (8.5-ppg density) with 100,000 lbm of 30/50 proppant at 5 ppa pumped at 10 bbl/min. Multiple iterations of the flow conduit were designed and analyzed to minimize the pressure drop, the flow velocity, the erosion rate, and recirculation. This design methodology enabled a successful qualification using a full-scale erosion test, followed by successful closing and pressure tests. Expensive retesting was eliminated; post-test correlations demonstrated that the CFD model accurately predicted areas of high erosion, and the quantity of material loss was within practical limits. The development approach and modeling method provide a reliable tool for the development of new gravel-pack completion equipment and comparable products, saving time and avoiding expensive delays, failure investigations, and retesting costs.
Abstract This paper presents a case study of the successful lower completion deployment of 13 swellable packers and Autonomous Inflow Control Valves (AICVs) into a 2227 ft open hole using a light workover rig in ADNOC Onshore (AON). The objective of the well was to reduce the well's high Gas to Oil Ratio (GOR) and increase production efficiency and profitability. The main concern as Drilling & Completion team was to recover the single oil producer completion and run it with lower completion safely to the Target Depth (TD) and meet the Asset team objective and requirements. The workover rig of 750 HP can reach up to 12,000’ target depth and the maximum overpull is 210 klbs where the planned target depth is 12,127’ MD/ 8922’ TVD. A pilot study was done on this well since the production team observed an increase in the GOR where the maximum value reached 2800 scf/bbl from 2016 to 2022. Despite the challenges presented by the light workover rig capacity limitations, deployment of 2227 ft lower completion with 13 swell packers in open hole with assurance of proper isolation, a dedicated engineering study, simulations and risk assessment were concluded during the planning phase focusing on these challenges and set the proper engineering solution through a Torque and Drag simulation and checking the feasibility of deploying lower completion using the 750 HP light workover rig. In addition, a proper hole cleaning was planned with the combined trip of open hole drift and scrapper. Furthermore, for wellbore segmentation isolation, two runs of mechanical caliper logs were conducted to guarantee optimal placement of swell packers and strive for proper isolation of each segment, which eventually supported the successful completion of the well as per plan. The study provides insights into the design, execution, and monitoring of maintenance work for workover wells that aim to retain their production rates. One of the major challenges of the well was the limitations of the rig capacity which will be highlighted in the study along with the methods used to address these limitations. Also, the use of AICVs, 13 swell packer deployment, equipment selection, real-time monitoring, expertise, pre-planning, torque and drag performance, design modelling, and simulations during the planning phase are some of the steps taken to eventually execute a flawless completion. A proper well cleanout and dedicated drift run were among some of the things carried out to make the deployment of the lower completion successful. The eventual results showed that the use of these techniques not only helped reduced the well's high GOR and thereby increased production efficiency and profitability but also was the main reason we were able to successfully get the lower completion to target depth. It is significant to highlight that one of the lightest WO rigs in the AON field successfully completed the well as Workover well.