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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Guan, Xu (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Zhu, Deyu (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Tang, Qingsong (PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Wang, Xiaojuan (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Wang, Haixia (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Zhang, Shaomin (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Deng, Qingyuan (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Yu, Peng (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Yu, Kai (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Huang, Xingning (Downhole service company of Xibu Drilling Engineering Company Limited, Karamay, China) | Xu, Hanbing (CNPC, International HK LTD Abu Dhabi, Abu Dhabi, UAE)
Abstract In recent years, tight sandstone gas as one of the important types of unconventional resources, has been rapid explored and developed. There are large-scale tight sandstone gas production in Sichuan Basin, Ordos Basin, Bohai Bay Basin, Songliao Basin and other basins, and it has become a key part in the area of increasing gas reserves and production in China. Due to the influence of the reservoir characteristics, tight gas reservoirs have low porosity and permeability, and the tight gas can only be effectively developed by improving the conductivity around the wellbore. Therefore, it is required to perform hydraulic fracturing after the completion of horizontal well drilling to improve the permeability of reservoir. It can be seen that hydraulic fracturing is the core technology for efficient development of tight gas resources. The implementation of hydraulic fracturing scheme directly determines the horizontal well production and EUR. This paper describes the workflow of 3D geomechanical modeling, technical application for Well YQ 3-3-H4 reservoir stimulation treatment, and carries out hydraulic fracture propagation simulation research based on 3D geomechanical model. This paper also compares the micro-seismic data with the simulation results, and the comparison results show that the propagation model is consistent with the micro-seismic monitoring data, which verifies the accuracy of the model. This paper clarifies the distribution law of hydraulic fractures in the three-dimensional space of horizontal wells in YQ 3 block, and the research results can be used to provide guidance and suggestions for the optimization of fracturing design of horizontal wells in tight gas of Sichuan Basin.
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.
Ekpe, J. (KOC Kuwait Oil Company) | Al-Shehab, A. (KOC Kuwait Oil Company) | Al-Othman, A. (KOC Kuwait Oil Company) | Baijal, S. (KOC Kuwait Oil Company) | Marin, G. (Weatherford) | Benyounes, H. (Weatherford) | Aliyeva, A. (Weatherford) | Alqabandi, R. (Weatherford) | Selami, B. (Weatherford) | Al-Fakeh, B. (Weatherford)
Abstract The development of Najmah-Sargelu (NJ-SR) limestone fractured reservoir, has a significant role in Kuwait Oil Company (KOC) 2040 strategy. To achieve this objective, hydrocarbon potential across the NJ-SR reservoir will have to be evaluated in the West Kuwait of Kra Al-Maru (Figure 1). First and foremost, this section will have to be drilled to planned section TD, cased off and successfully cemented. This paper discusses KOC experiences and best practices implemented to ensure utilizing managed pressure drilling equipment to achieve a successful 7-5/8-in liner cement job at well depth of 16,945ft. MD (15,756ft. TVD), and reservoir pressure and temperature ranges of 12,000 - 15,000psi and 230 - 280 deg F respectively. This new approach to cementing is based on Managed Pressure Drilling technology. It addresses running the 7-5/8- in liner and cementing it in MPD mode. A step-bystep procedure is provided that ensures a constant bottom pressure is maintained throughout the process. Risk assessment showing what can go wrong and mitigations are provided, and the method is described in detail to allow readers comprehend the unique case presented in this paper. Managed Pressure Cementing (MPC) technique in case study well is compared to offset wells in West Kuwait Field where cementing was conducted conventionally. In most cases, the cement bond logs show cement dispersed throughout the annulus with no continuous bond - channels in the cement behind the casing. The most significant new findings from this paper are that, in a couple of wells where there were no losses while pumping cement conventionally- the cement bond logs showed moderate to poor cement behind casing and channels within the cement. This technology offers opportunity to achieve good cement bonding with liner in fractured limestone which can be problematic due to the risk of losses and the presence of hydrocarbons with high pore pressure in West Kuwait NJ-SR intervals. This novelty approach using Managed Pressure Cementing technique to case and cement liners in West Kuwait fields and tight margin reservoir will ensure good cement bond logs behind casing and improve well testing and completions strategies.
Al-Samhan, Amina (Kuwait Oil Company, Al-Ahmadi, Kuwait) | Jilani, Syed Zeeshan (Schlumberger, Al-Ahmadi, Kuwait) | Al-Nemran, Shahad (Kuwait Oil Company, Al-Ahmadi, Kuwait) | Muhammad, Yaser (Schlumberger, Al-Ahmadi, Kuwait)
Abstract The Greater Burgan field has been on production for over 75 years mainly from the homogenous massive sands of the Burgan clastic sequence. Given the increasing field water cut from these sands, it is now a matter of strategic focus for the asset to target the generally untapped thin, laminated low quality sands to sustain target production. This paper focuses on a case study for a horizontal well design and completion optimization using sector modeling. An updated dynamic model, covering the area of interest, was developed. This is an extremely important tool to achieve the study objectives. A sector model was cut out from the full field dynamic model. Grid refinement was performed on the sector, in both vertical and horizontal dimensions. Newly drilled wells were used to update the model horizons, petrophysical data from offset wells in the sector, including geosteering data from the pilot hole, were upscaled and properties populated across the model. The dynamic model calibration was conducted successfully by including all available well events, workovers, production data, static and flowing bottom hole and well head pressures including all other surveillance data from offset wells. To better match the historical field pressure and water-production, sensitivities were conducted to determine the model response to various parameters including the aquifer strength and faults conductivity. Adjustment of the aquifer strength enhanced the field pressure match, invariably improving the calibration of the model. After model calibration, the horizontal well was implemented in the model, in line with the design scope from the asset. The biggest uncertainty was the oil-water contact (OWC) in the sector near the planned well. Although offset wells gave a reasonable estimate of the OWC, it was used as sensitivity parameter to cover the uncertainty. This was taken forward into the model prediction simulation work. The modeling study provided immense insights into the probable outcomes in terms of actual horizontal well production deliverability. Multiple rate sensitivities were conducted mimicking the different choke sizes which were planned. These were used as a guide for the asset to set reasonable production target rates for the well. The study also provided a technical justification for completion recommendations and optimization with a view to maximizing the well's production over time. The horizontal well has been drilled, completed, and tested in the field. The production test rates were encouragingly consistent with the model predictions. The workflow methodologies adopted in this work have now been extended to other wells being drilled in the field.
Abstract With the emerging necessity of carbon capture and storage (CCS), many companies are evaluating the possibilities of CCS implementation in their assets. Technical evaluation for converting existing fields to CCS projects includes various topics such as carbon dioxide (CO2) transportation and its economics among other topics. Selecting a method for CO2 transportation becomes important when the target site is distant from the CO2 source, particularly if located offshore. The Intergovernmental Panel on Climate Change (IPCC) special report on CCS has identified that a liquefied CO2 (LCO2) carrier would be the lowest-cost option for distances more than 1700 km. An LCO2 carrier can also be the best option when transporting CO2 abroad to benefit from the international carbon tax, which has been collecting global interest. Along with this increased interest in LCO2 carriers, shipbuilding and engineering companies are developing their ships. When an LCO2 carrier is used for offshore CCS, the ship would be located right above the target site to minimize the length of pipelines. As this distance between the LCO2 carrier and the target reservoir is shorter than other transportation options, the traditional modeling approach uses a standalone model of the LCO2 carrier. This approach excludes pipeline models when estimating required operating conditions of the carrier assuming a fixed outlet boundary condition. However, this boundary condition may differ from the actual value. Furthermore, in real systems, operating conditions (i.e., pressure and temperature) are not constant over time. Ignoring the dynamic interaction with downstream pipelines may lead to subsequent differences in simulation results. The actual thermo-hydraulics behavior of LCO2 carrier cannot be reproduced when standalone models are introduced. In this study, a standalone LCO2 carrier model and an integrated dynamic CCS model connecting the LCO2 carrier, injection equipment, riser, pipeline, and wellbore were developed. The standalone LCO2 carrier model predicts the behavior of a whole ship from two LCO2 tanks to the carrier's outlet, which would be connected to the riser of the CO2 injection system. The integrated model calculates the whole CO2 injection system from two LCO2 tanks to the target reservoir by linking the standalone LCO2 carrier model and a flow model starting from the riser to the injection wellbore. The simulation results showed that the required CO2 pump discharge pressure of the integrated model was 5 bar higher than the standalone model to meet the target flow rate. As the required discharge pressure increased, the average speed and power consumption of the CO2 pump increased by 2.5% and 7%, respectively. In this comparison study we demonstrated that the integrated model could accurately represent the overall system behavior. No risk of solid CO2 formation was identified during unloading of two LCO2 tanks. By using the developed integrated model, three different case studies were conducted to analyze the effect of rigorous heat transfer in LCO2 tanks, simultaneous tank unloading, and initial startup operation on the thermal-hydraulic performance of the system, respectively. The first case demonstrated that modeling the tanks with high-thickness thermal insulation is close to an adiabatic condition. The required discharge pressure of the CO2 pump was the same, and the final pressure and temperature of the tank holdup increased by 1 bar and 2°C, respectively. The second case showed that changing the operation from sequential to simultaneous unloading of the two LCO2 tanks removed the disturbances observed during the transition of tanks in the sequential case. This removes potential instabilities in the pump controller and avoids any impact on the injection system performance. The unloading time was only 20 seconds shorter, and the required pump discharge pressure was the same. The third case demonstrated that the integrated model could analyze the initial startup operation, which displaces nitrogen (N2) and methane (CH4) in the pipelines and wellbore with CO2, which standalone models cannot predict. It took 500 seconds to fully displace N2 and CH4 in the system with CO2. Furthermore, the required valve opening time (19 seconds after injection commences) to prevent backflow from the reservoir could be determined. In conclusion, dynamically integrated modeling can help identify interactions that are not apparent in the traditional standalone modeling approach. The integrated model can evaluate system behavior and possible operational risks that cannot be observed in standalone models. Simulation results in this work demonstrated that the dynamically integrated CCS model captures more realistic behavior of the whole CO2 injection system to help optimize the design and operation of a CCS project. Developing a plan to address these interactions through the integrated dynamic simulation can result in a more stable operation.
Abstract The most challenging section in drilling directional wells is the curve section. This curve section used to be drilled by a conventional steerable motor with a slide/rotate decision with the greater challenges of poor hole cleaning efficiency and increased drilling time. The Rotary Steerable System (RSS) was introduced in a turnkey project by eliminating slide and rotate limitations to reduce the cost per foot. Initially, the downhole automation of the RSS was limited to holding verticals and inclinations. Later, the closed-loop control progressed to hold inclination and azimuth, but the curve section remained unautomated. The driller continued to drill the curve section manually by adjusting the steering parameters. A new Autonomous Downhole Control System (ADCS) recently integrated into the RSS enables autonomous drilling of the curve section, further reducing human inconsistencies and improving borehole quality, drilling efficiency, well economic, and reducing carbon footprint. Multiple offset wells were analyzed. Different BHA configurations were studied with various stabilizations to increase the dogleg capability. Bit records were gathered and analyzed for steerability and stability. The trajectory design was revisited to ensure minimum dogleg severity was considered at the planning stage. This ensured staying within the RSS's technical limits and avoiding unplanned pulling out of the hole due to failure to maintain the trajectory. The specific field strategy was prepared with the digital journey of intelligent planning, intelligent execution, surface automation, and downhole automation. The RSS was incorporated with the newly developed ADCS, placing the driller into the supervisory role to monitor the digital drilling system. The RSS was introduced in a turnkey project to reduce the cost per foot by improving the ROP, drilling shoe-to-shoe in one run, having efficient hole cleaning to avoid stuck pipe incidents, and having a smoother borehole for running casing and liner. The new ADCS incorporated into the RSS completed the automation puzzle and has been tested successfully in many wells on the same project. It transfers human decision-making to the downhole control, further increasing ROP in some cases by up to 100% and up to three days saved on each well drilled. This paper will illustrate the detailed BHA change in curved and horizontal sections from mud motor to the RSS with the significant progression of downhole automation and a future view for autonomous drilling in similar fields worldwide.
Summary Elemental mercury (Hg) is a common trace contaminant associated with corrosion of infrastructure impacting exploration, production, and processing of commercial hydrocarbons. Presently lacking is a model for the quantitative prediction of Hg concentration in reservoir fluids, sufficiently reliable for process engineering applications and design of mitigation strategies to ameliorate the potential risk of Hg presence. In this paper, we present a thermodynamic equilibrium mineral-based model for predicting the solubility of mercury in hydrocarbons, Hg(org), at in-situ reservoir conditions. The model is based on literature experimental data on the solubility of Hg in a mixture of alkanes, in equilibrium with Hg, H2S, O2, cinnabar (HgS), and water. As the model inputs are based on the chlorite-pyrite-H2S model, its application should primarily be limited to clastic hydrocarbon-bearing reservoirs. A global data set of Hg in hydrocarbons reveals a remarkably strong association with the presence of humic coal in subsurface formations. Assuming that pure stoichiometric cinnabar (HgS) is stable at the reducing conditions typical of hydrocarbon reservoirs (i.e., aHgS = 1) results in an overestimation of Hg(org) solubility by up to three orders of magnitude relative to globally reported concentrations of mercury in natural hydrocarbons. A statistically robust match between model and observed concentrations of Hg(org) was achieved using an aHgS of 0.003, consistent with reported concentrations of Hg from pyrite (FeS2) in coals and hydrocarbon reservoirs. The model has been validated in a case study of reservoir Hg reported in the Gorgon North-1 well, North West Shelf (NWS), Australia. The dominant process of cinnabar precipitation is by oxidation, particularly in the near-surface environment where reduced Hg-bearing hydrocarbons mix with shallow oxygenated or acidic surface waters. Such processes are typical of the environments where most downhole fluid samples are collected during drilling, sampling, and cleanup of exploration and development wells. This leads to the invariable conclusion that much of the particulate mercury species, specifically HgS, collected with hydrocarbon fluid samples, are metastable with respect to the dissolved Hg(org) in hydrocarbons at reservoir conditions and should not be included in the estimation of total Hg (i.e., THg) in hydrocarbons. This hypothesis has been confirmed by an extended well test in the Minami-Nagaoka gas condensate field, where it was observed that Hg dissolved in produced water decreased to negligible levels over time, while the Hg(org) in the condensate liquid reached a stable value like what the new Hg(org) solubility model would predict for in-situ reservoir conditions.
Sofi, Abdulkareem (Saudi Aramco) | Wang, Jinxun (Saudi Aramco (Corresponding author)) | Salaün, Mathieu (Solvay) | Rousseau, David (IFP Energies Nouvelles) | Morvan, Mikel (Solvay) | Ayirala, Subhash C. (Saudi Aramco)
Summary The potential synergy between smartwater and various enhanced oil recovery (EOR) processes has recently attracted significant attention. In previous work, we demonstrated such favorable synergy for polymer floods not only from a viscosity standpoint but also in terms of wettability. Recent studies suggest that smartwater synergy might even extend to surfactant floods. In this work, we investigate the potential synergy between smartwater and surfactant flooding. Opposed to previous work, the potential synergy is investigated from ground zero. We concurrently developed two surfactant formulations for conventional high-salinity injection water and low-salinity smartwater. To design the optimal surfactant-polymer (SP) formulations, we followed a systematic all-inclusive laboratory workflow. Oil displacement studies were performed in preserved core samples using the two developed formulations with conventional injection water and smartwater. The results demonstrated the promising potential of binary surfactant mixtures of olefin sulfonate (OS) and alkyl glyceryl ether sulfonate (AGES) for both waters. The designed binary formulations were able to form Winsor Type III emulsions besides achieving ultralow interfacial tensions (IFTs). Most importantly, in terms of oil displacement, the developed SP formulations in both injection water and low-salinity smartwater were capable of recovering more than 60% of the remaining oil post waterflooding. A key novelty of this work is that it investigates the potential synergy between smartwater and surfactant-based processes from the initial step of surfactant formulation design. Through well-designed from-scratch evaluation, we demonstrate that surfactant-based processes exhibit limited synergies with smartwater. Comparable processes in terms of performance can be designed for both high-salinity and low-salinity waters. It is also quite possible that the synergistic benefits of smartwater on oil recovery cannot be effective in SP flooding processes, especially with specific surfactant formulations under optimal salinity conditions.
Ahmad Mohammed AlMatar, Mohammed (Kuwait Oil Company) | Al-Bahar, Zakaria (Kuwait Oil Company) | Mahmoud Bastaki, Fahad (Kuwait Oil Company) | BinOmar Chong, Mizan (Kuwait Oil Company) | Hamed Barki, Jassim (Kuwait Oil Company) | Jamal, Mariam (Kuwait Oil Company) | Al-Mehene, Mehanna (Kuwait Oil Company) | Slama, Mohamed Hedi (SLB) | Badrawy, Kareem (SLB) | Molero, Nestor (SLB) | Pochetnyy, Valentin (SLB) | Adel Sebaih, Mohannad (SLB)
Abstract Horizontal drilling technologies have evolved during last decades making possible wells with thousands of feet of long horizontal sections. These drilling advancements have contributed to drill more intricate multilaterals wells to ensure a thorough contact with the reservoir. In terms of well accessibility for rig-based well interventions, these complex completion configurations add significant challenges. Upon drilling is completed, coiled tubing (CT) matrix acid stimulation is one of the first interventions used to remediate the formation damage and bring the well back on production. Operator in Kuwait drilled a level four six-legged multilateral well in the north area to maximize reservoir contact within lower and upper Tuba carbonate formations. This drilling approach enables several production schemes and versatility in the pursuit of economical production. As such, this completion approach required an advanced intervention technique that relied on CT optical telemetry and multilateral entry tool (MLT). Real-time downhole readings included casing collar locator (CCL), gamma ray, CT internal pressure, annulus pressure, annulus temperature, and axial force for accurate depth control, rapid lateral identification, optimal MLT actuation and understanding of dynamic downhole conditions along the operation. The level-four multilateral candidate had a six 6 1/8-in. uncased horizontal sections that needed cleanout from drilling oil-based mud (OBM) and matrix stimulation using an emulsified retarded acid system (ERAS) for enhanced wormholing into the carbonate rock. The lateral sections exhibited an average of 2,500 ft and the reservoir featured a bottomhole temperature near 130°F and bottomhole pressure close to 2,100 psi. By combining real-time optical telemetry with MLT, the profiling of three laterals was completed in less than 4 hours for each one, optimizing the rig time and the course of the treatment. Prior to the matrix stimulation, three laterals were conditioned via CT through a multifunctional solvent consisting of a synergistic blend of aromatic solvent and surfactants intended to breakdown and disperse OBM residuals without the need of mechanical agitation and also leaving the rock water wet. The three laterals were then acidized in a single run by pumping 450 bbl of multifunctional solvent followed by 1,500 bbl of ERAS. When compared to conventional CT intervention in multilateral wells, this enhanced intervention approach optimized the total intervention time by 33%, being fundamental the ability to make fast-informed decisions from optical telemetry. This paper documents a value case study for CT rig-based intervention in Kuwait, where combination of an array of technologies, such as CT optical telemetry, MLT, multifunctional solvent and ERAS, enabled cleanup and acidizing three laterals from six-legged multilateral wells in a single run. The lessons learned are now the reference for other operators in the Middle East for performing interventions in multilateral wells.
Ahmad Mohammed AlMatar, Mohammed (Kuwait Oil Company) | Al-Bahar, Zakaria (Kuwait Oil Company) | Mahmoud Bastaki, Fahad (Kuwait Oil Company) | BinOmar Chong, Mizan (Kuwait Oil Company) | Hamed Barki, Jassim (Kuwait Oil Company) | Jamal, Mariam (Kuwait Oil Company) | Al-Mehena, Mehanna (Kuwait Oil Company) | Slama, Mohamed Hedi (SLB) | Badrawy, Kareem (SLB) | Molero, Nestor (SLB) | Pochetnyy, Valentin (SLB) | Adel Sebaih, Mohannad (SLB)
Abstract Following the rig-based well testing stage, completion programs of high-pressure wells in North Kuwait call for well killing with heavy oil-based mud (OBM). The workover rig is then demobilized, and production flowlines are installed. Well activation plans are carried out riglessly, and coiled tubing (CT) is instrumental to bringing the wells back to sustainable production. One of the major drawbacks from this practice is the formation damage generated by the OBM, which often requires additional interventions for remediation. To address this limitation, a new approach leveraging instrumented CT for temporary well suspension was recently implemented. Real-time downhole telemetry is enabled by an optical line installed in the CT pipe and used to accurately set a through-tubing inflatable packer (TTIP). Once the latter is anchored at the planned depth, above the interval open to the formation, CT is disconnected from the packer assembly, and the fishing neck is protected with a sand plug. CT is then retrieved to surface, and a slickline dump bailer is run to spot cement on top of the sand plug. Once the cement has set, CT is run to displace the wellbore to kill fluid. Two pilot wells were selected to implement this new approach for temporary well suspension. Both wells had a maximum potential wellhead pressure in the order of 7,400 psi, and 15.0-ppg OBM was originally planned for well suspension purposes. Upon completion of the zonal testing program - which included initial stimulation, well activation, and flowback - instrumented CT was run with high- pressure rotary jetting to condition the TTIP setting depth and displace the wellbore with brine, after which, a shut-in wellhead pressure near 2,000 psi was observed. In the next CT run, TTIP was set close to the end of the production tubing, and critical stages, such as depth correlation, packer inflation, and packer anchoring testing were closely controlled via real-time downhole measurements. Additional verification of the TTIP effective seal was carried out before the CT was disconnected from the packer assembly through an inflow test relying on live downhole pressure monitoring. Once the TTIP released, the temporary suspension was completed following the methodology described above. Finally, the wells were observed at surface with zero pressure for more than 24 hours, receiving acceptance from the operator. This alternative approach for temporary well suspension represents an innovative solution to bring wells back into production without additional restimulation or well activation. This methodology greatly relies on CT real-time downhole telemetry, and operators from the Middle East can benefit from the experience gained in this project.