bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Methodology of Slot Recovery Minimizing Milling Operation
Authors: Sato Ryosuke , Abdelkarim Islam Khaled , Albeshr Abdul Rahman Hasan , Toki Takahiro , Al Ali Salim Abdalla , Alzaabi Mohamed Abdulrahman , Malpass Paul , Barbera Roberth 
Published: May 2021

Abstract
Slot recovery operation can be considered as one of the most time consuming operation. Cut and pull casings, or milling casings have been carried out as typical method of slot recovery. However there are a lot of risks with this typical method such as poor progress of milling, damaging top drive due to high vibration while milling or sudden string jumping up while overpulling and possibility of string stuck caused by poor hole cleaning while milling. We have completed slot recovery operations on numbers of wells, but there were a lot of troubles caused by above mentioned adversaries on rig equipment and taking a lot of time to complete operation.
There are several kinds of new slot recovery technologies that may save rig time and less harmful than conventional method. Casing Pulling Tool (CPT) is one of the new technologies which eliminates or mitigates risks mentioned above. CPT has piston internally and it is activated by applying pressure inside string. CPT is run with casing spear and drill pipes. Once spear is engaged with casing and apply pressure inside drill string, CPT provides pulling force on casing. Pulling force is varied depend on the applied pressure and maximum available pulling force is more than 1,000 kips. Hence upper part of string is anchored at rotary table by slips, pulling force is applied on casing and drill string below rotary table. This means no pulling force is applied on top drive and minimize the chance of getting damage on it.
As an actual case, we could successfully recover 13-3/8" casing by CPT without having any troubles and complete slot recovery operation with saving rig time compared to the conventional methods.
This paper introduces the details about the case mentioned above.
Production Casing Regains Integrity by Repairing Shallow Leak with Microfine Cement
Authors: Al-Khaldy Meshal , Al-Saadi Dhari , Al-Ajmi Mohammad , Al-Banai Mohammad , Elafify Ibrahim , Jaber Fajar , Al-Dakheel Rashed , AlBohamad Dalal , Ekwue Ann-Marie , Hussain Khadar , Kunchur Basavaraj , Svensen Dan 
Published: May 2021

Abstract
While carrying out planned workover activities, production casing had to be tested to verify integrity. A shallow leak was observed across the production casing at about 1000 ft MD from surface.
External and/or internal casing corrosion especially across relatively old wells, could lead to such inconsistency, moreover that major challenge to address and react such surprises online while operation meanwhile nothing to help as a pre-planning studies.
Further production objectives require casing integrity as per ESP design to protect shallow aquifer sources. Numerous attempts to repair the casing leak by performing remedial squeeze operations utilizing conventional cement slurry designs proved unsuccessful.
Other ideas were considered such as deploying a scab liner to cover the damaged casing section, however this was discounted as it would introduce undesirable borehole restrictions; as well as extra 6 days for running, cementing and clean-out.
A novel engineered approach with Microfine cement slurry design squeezed into the damaged zone successfully regained casing and well integrity, while maintaining full borehole access through the production casing, thus saving rig time and tangible cost.
Well drilling operations should be carefully designed and executed targeting the integrity assurance by providing the right casing metallurgy and good cementation for proper zonal isolation behind individual casing strings to mitigate external casing corrosion and act as the first line of defense against corrosion and any potential leakage or cross flow among different formations across the life span of the well.
Well completions should be installed / tested considering the protection of inner production casing / liner from getting in prolonged contact with wellbore fluids, to avoid excessive internal corrosion and achieve reservoir fluid containment across the life of the well.
A proactive approach been raised to acquire production casing / liners corrosion logs across workover activities especially regarding old wells to enable the mapping and interpretation of casing wall thickness / corrosion progress along the well life. That approach could aid in predicting the condition of production strings before commencing planned workover activity; and thus justify the availability of back-up repair plan to maintain rig operations and avoid any unscheduled operational surprises and possible strategic production rate defer.
Overcoming Thin Reservoir Geosteering using Advanced Technique in Sultanate of Oman
Authors: AlGhamdi Sarah Mohammed , Beche Amina , Awadalla Muhannad , Naamani Hafidh , Aljiroudi Fadi , Hashemi Alkhalil , Siyabi Khalid , Hooti Younis 
Published: May 2021

Abstract
Drilling long laterals within Shuaiba limestone reservoir without exit to Nahr-Umar shale in the challenging field "B" that is characterized by geological uncertainty can have major risks. The low to very low resistivity environment reservoirs are common in Oman especially while placing wells nearby OWC; on a reservoir spot window of 1-2m TVD only.
The main objective is to place the well less than 1m TVD below the reservoir top, this was achieved by utilizing Multilayer Bed Boundary Detection and Rotary Steerable System.
Integrating propagation resistivity curves response with the directional resistivity curves response from Bed Boundary detection tool have been used as a guide for an optimal well placement in low resistivity reservoir, along with Rotary Steerable System are one of the best strategies which have been used to place the wells within the right spot.
For tight geosteering window with an aggressive formation tendency pushing the azimuth left or right and continues inclination instability associated with the existence of an interbedded layers of hard streaks within the reservoir, a faster and more competent Rotary Steerable System tool and Bit selection is required, as proven it provides better stability results for achieving well placement objectives and respond in fast manner to geosteer in real time.
The objective of this paper is to describe the geosteering logging while drilling (LWD) technology and technique and Rotary Steerable system (RSS).
Advanced Wellbore Surveying Technology Extends the Drilling Limits in Offshore Operation
Authors: ElGizawy Mahmoud , Ness Knut , Kolakkodan Saleel 
Published: May 2021

Abstract
Wellbore surveying is critical while drilling in order to assure the drilled well is following the plan and is penetrating the geological target. Additionally, wellbore surveying is the key to allowing a well to be drilled safely, avoiding other wells drilled in the same field, and optimizing reservoir production. Standard wellbore surveying accuracy is increasingly inadequate for optimizing the well placement in real time to maximize the reservoir recovery due to maturity of the field. The other disadvantage of the standard wellbore surveying often requires running an additional wellbore surveying tool to improve the accuracy in order to manage the collision avoidance with nearby wells in the same field, introducing unwanted time and costs. Hence, this article presents the advanced wellbore surveying technology that is successfully implemented in offshore fields of Abu Dhabi to overcome the limitations of the standard surveying accuracy without compromising rig time.
Magnetic measurement while drilling (MWD) surveys are common standard and utilized in every directional well in this operation. To overcome the standard accuracy limitation, advanced survey correction to the magnetic MWD surveys is introduced. This includes in-field referencing to provide a higher resolution magnetic reference to calculate a more accurate well direction, correction to the effect of the steel components in the bottom hole assembly on the magnetic MWD surveys, correction to the errors associated with survey sensors calibration, and correction to any misalignment between the survey tool and the wellbore.
Correcting the surveys in real-time while drilling is the key to placing the well accurately and to avoid offset wells in the close proximity. The details of the corrections methodology are discussed. Advanced magnetic survey correction procedures in real-time are outlined and mapped out. Finally, results of improving the magnetic surveys while drilling in placing the wells and minimizing the collision risk of offset wells are presented. This advanced survey technology allows drilling previously un-drillable wells in these offshore fields, and the allowance for increased density of wells in the reservoir gives the operator opportunity to maximize production recovery and extend the life of reservoir.
Higher accuracy of wellbore surveys is an increasing requirement in mature fields to safely allow more accurately placed wellbores with the required production rates. This allows for improved well placement along the trajectory facilitating adjustment at control points and landing points to maximize the hydrocarbon production. In addition, it allows controlling the probability of collision with any nearby wells. The enhanced wellbore surveying accuracy is achieved by advanced magnetic survey corrections in real time. This is controlled by a stringent novel process and communication protocol in order to meet the accuracy objectives.
Automation of Formation Tops Estimation Dramatically Reduces Well Planning Process Duration
Authors: Salimov Rail , Torres Javier , Al Katheeri Yousif , Alhammadi Yousef , Abdelrahman Ahmed 
Published: May 2021

Abstract
Aiming to make the well planning process leaner and agile focusing on duration reduction without compromising quality of deliverables, automation opportunities have been identified within the multi-discipline iterations. The two key criteria considered for the selection of the automation project were: Minimum deployment effort and Maximum value added in efficiency.
The initial project objective was to calculate formation tops for a well engineer without requiring the intervention of a geoscientist using commercial software. The methodology utilized is the following: 1. Inputs: Well trajectory and Surfaces. 2. Process: The algorithm finds intersections between surfaces and well trajectory. Surfaces and trajectory are represented as a set of XYZ points. To find the intersection, the software iterates through each point of the trajectory from the top, comparing the depth of the projection to the target surface. The projected depth to the surface is found by 2D interpolation of the surface. Once the trajectory point becomes deeper than the surface projection, the intersection is estimated using geometrical considerations of similar triangles. 3. Deliverables: Estimated formation tops for the given trajectory. 4. Results: Simple in-house developed software enhanced well planning workflow in an Offshore Green Field. The software converted to single executable file and can be run on any device without the open-source software installed. Very accurate results achieved with proposed algorithm with a negligible difference of 0.5 feet with the geoscience traditional software.
Well planning duration reduced from average 1 week to 1 or 2 days. The workload for well engineers and the asset team has been dramatically reduced. Reduction of the number of commercial geoscience software licenses required.
Way forward: A test with a slightly modified code was used to generate formation tops for more than 400 well in a Long-Term Field Development Plan project for a Brown Field during feasibility study. Upscale to all the Fields within the organization. Improve User Interface for better adoption. Include more formats for both, trajectories, and surfaces. Reduce computing time.
This project represents the first initiative in the organization aiming to automate the well planning process.
Overall, it represents the beginning of a journey where multiple opportunities for automation can be achieved using an open-source coding software that allows any engineer with little to no experience coding to being able to generate solutions to address daily challenges.
Novel Solution For Curing Total Losses in Highly Fractured Reservoir Formation on a Major Oil Producing Field in the Middle East
Authors: Ovwigho Efe Mulumba 
Published: May 2021

Abstract
The reservoir formation in a major oilfield in South of Iraq is highly fractured. The operator has set as requirement that any losses had to be cured before drilling ahead. Whenever losses are encountered, drilling is stopped to cure the losses, most of the times spotting at least four cement plugs before drilling ahead are required. The current process leaves the well in an underbalanced condition for a long time posing well control risk. It was necessary to come up with an optimized solution that reduces this exposure.
Drilling the entire reservoir formation to expose all loss zones before spotting cement plugs to cure all the losses was the first step taken. Secondly, since encountering total losses across the reservoir formation was inevitable, redesigning the cement slurry formulation was an objective. Many alternative designs were proposed but were disqualified as some of the chemicals or fibers were not bio-degradable causing some damage to the reservoir. After a consensus between all parties, it was proposed to introduce temperature-degradable fibers into the cement slurry. Pilot tests were performed at maximum anticipated downhole temperature which proved successful.
The analysis results from the lab were approved and one well was assigned for the field test of the proposed solution. The selected well was drilled to expose all the loss zones, losses were encountered as expected, cement slurry incorporated with temperature degradable fibers was spotted which resulted in all the losses getting cured at the first attempt. This solution was tested in all subsequent wells drilled on the field achieving the same successful result. This solution has since been adopted for curing total losses encountered across the reservoir formation in this field as it ensures that less time is spent on curing losses, less cement material is consumed and those wells are delivered quicker and at reduced cost. This solution has led to average savings of approximately 5 days per well drilled subsequently on this field. Previously it took an average of 166 hours to restore fluid well control barrier (see wells 1 and 2 in figure 2), these days in 52 hours fluid well control barrier is fully restored barrier (see wells 3 and 4 in the attached image). Well control risk is greatly reduced.
This paper will show how minor changes to operational procedure and improvement to conventional solutions can greatly impact well control and the quick restoration of well barrier element when drilling across highly fractured reservoir formation. It will also discuss the comprehensive analysis of the loss zones, the cement laboratory analysis, the trial jobs, the measures that were put in place to reduce operational risks in order to ensure that the job was executed successfully.
A Gas Kick Model that Uses the Thermodynamic Approach to Account for Gas Solubility in Synthetic-based Mud
Authors: Manikonda Kaushik , Hasan Abu Rashid , Rahmani Nazmul H. , Kaldirim Omer , Obi Chinemerem Edmond , Schubert Jerome J. , Rahman Mohammad Azizur 
Published: May 2021

Abstract
This paper presents a rigorous, mechanistic model for simulating a gas kick, that uses the thermodynamic approach to account for gas solubility. This thermodynamic solubility model uses the pressure and temperature data from the kick simulations and estimates the mole fraction of various gas components in the liquid phase. We validated these gas solubility results using Aspen HYSYS, a commercial chemical process simulation software.
The thermodynamic solubility model presented in this paper assumes a pure-methane kick and applies the concepts of phase-equilibrium and fugacity to estimate the amount of dissolved gas in the drilling fluid. Application of fugacity equilibrium between the gas and liquid phases, in conjunction with the Peng-Robinson equation, gives the liquid phase mole fraction of methane. The analytical kick model uses the Hasan-Kabir two-phase flow modeling approach to describes the changes in pressure during kick migration, at various points in the annulus. Since the expansion of the gas bubbles depends on the variation in pressure, these studies also lead to pit gain estimates.
A comparison between our model results and HYSYS values for methane liquid-phase mole fraction showed a maximum 8% deviation with complete agreement on bubble point (Pb) pressure and location estimates. Similarly, our model calculated the solution gas-oil ratio (Rs), with a maximum divergence of 3% from HYSYS estimates. From the comparison studies with other empirical Bo & Rs correlations, we note that the estimates of our model agreed best with those of O’Bryan’s (O'Bryan 1988) correlations.
Many numerical kick simulators exist today, but they are notoriously time-consuming, limiting their on-field utility. Our kick simulator’s simplicity makes it potentially useful for on-field well control decisions. Most of these existing numerical simulators ignore the effects of kick solubility in synthetic-based muds. In the few models that do not ignore solubility, the approach to accounting for gas solubility and mud swelling is empirical, limiting their usage under conditions beyond the range of the source data used in developing these correlations. The mud swelling calculation approach we developed does not have these pressure and temperature range limitations.
New Approach for Abandon and Side Track Cement Plugs in Long & High Deviated Wells
Authors: Kassem Youssef Ali , Hassan Mahmoud Mohamed , El-Atrache Bassam Jamal , Ahmad Moustafa Ahmad , Al Kindi Rashid Khudaim , Alwahedi Khalid Ahmad , Al Marzooqi Abdul Mohsen Mohamed , Hammadi Majed Ismail 
Published: May 2021

Abstract
One of the biggest challenges in Oil and gas industries is placing a proper abandonment and sidetrack cement plugs in long and highly deviated wells like ERD wells.
As per ADNOC offshore strategy for introducing new technology and practices to overcome operation challenges. ADNOC offshore drilling team worked together with one of the oil and gas services provider and came up with an innovative idea and technique by using available equipment and implementing a new procedures and practices to ensure well integrity by placing a long abandon cement plug in highly deviated well across hydrocarbon bearing reservoir.
The new tools and technique implemented successfully in two wells X01 and X02 in one of ADNOC offshore fields.
The new idea started from planning phase by working together with Services Company, where the assigned team went through all required job planning and check the proper tools to use with the best procedures. The team faced some challenges in relation to tools and equipment availability, which affected the first trial job. However, these challenges mitigated in the next job. The new technique proved advantageous by avoiding cement plug failures during abandon and sidetrack cement plug placements jobs, in optimum time and efficient way while reducing cost. This technique subsequently introduced to all ADNOC Offshore drilling teams and to be implemented in future wells.
Enhancing the Drilling Performance Management on a Large Drilling Operation
Authors: Handoko Alvin Ivan , Khella Henry Edward , Couzigou Erwan , Al-Marzouqi Adel Abdulrahman 
Published: May 2021

Abstract
Since the implementation of the Drilling Performance Department in late 2017, ADNOC Offshore has been able to develop a company performance-oriented culture among the drilling teams. This performance culture is reflected in 25% ILT reduction in 2018 and 12% in 2019. Furthermore, 37 NPT RCA cases were investigated and concluded in 2019, which resulted in 57 actions for tracking and closure.
With 5 (five) concessions, 9 (nine) different shareholders, and 39 (thirty-nine) rigs, drilling performance management is challenging. ADNOC Offshore created a centralized Drilling Performance Team to capitalize on this diversity as an opportunity to improve the traditional drilling performance role. This paper describes the team's approach on Drilling Performance and the consecutive result.
The team enhances the typical drilling performance role of Key Performance Indicator (KPI) management and reporting by adopting the Performance Opportunity Time (POT) and Root Cause Analysis (RCA) Process. At the same time, the Drilling Performance Team facilitates the flow of information between teams to ensure effective knowledge transfer within such a large organization.
The POT concept tackles the well duration reduction through the reduction of Invisible Lost Time (ILT) and Non-Productive Time (NPT).
To reduce the ILT, the team took advantage of the extensive technical background in the various drilling teams. Performance improvement initiatives were proposed by taking references from different teams within ADNOC Offshore and evaluating the application in other concession. Other approach is to compare with out-of-company references.
For NPT reduction, the innovative approach was to use the HSE Root Cause Analysis (RCA) concept. This RCA process led by the Drilling Performance Team was implemented to standardize the approach and have a systematic investigation analysis. This process resulted in identifying root causes and effective corrective action plans. As per HSE, addressing the root causes of incidents would result in the most significant impact in NPT.
This approach also allows an independent and more detailed look on the subjects, where commonly these tasks are done in a limited manner by drilling teams alone with their ongoing operational workload. Finally, results are communicated to the drilling organization through lessons learned portal and technical bulletins.
Improving Rate of Penetration in High Pressure High Temperature Gas Wells by Utilization of Managed Pressure Drilling and Artificial Intelligence
Authors: Ghamdi Ahmed , Saihati Ahmed , Abdelrahman Mohamed , Omar Mahmoud , Abdulraheem Abdulazeez 
Published: May 2021

Abstract
Drilling in deep high-pressure high-temperature (HPHT) abrasive sandstone pose significant challenges: low rate of penetration (ROP), bit wear, differential sticking, and wellbore instability issues. These issues are magnified when attempting to drill long laterals in the direction of minimum stress.
This paper focuses on the use of Managed Pressure Drilling (MPD) and Artificial Intelligence (AI) analytics to improve ROP.
MPD is normally used to help drilling in formations with narrow mud weight window, it achieves this by controlling the surface backpressure to keep the annular pressure in the wellbore above the pore pressure and below the fracture gradient. One key benefit of using MPD is that high mud weight is no longer required, since the Equivalent Circulating Density (ECD) is going to be managed to maintain the overbalance. An example of a well that was drilled using MPD solely for ROP improvement is presented in this paper. This well achieved almost double the ROP of a control well, which was drilled in the same formation with no MPD.
Essentially most of the drilling parameters used, which include, pump rate, revolution per minute (RPM), weight on bit (WOB), and other drilling practices, are controlled by the people on the rig. Incorporating AI analytics in the equation, help minimizes human intervention and could achieve further improvement in ROP. After the ROP improvement observed while using MPD, both technologies were combined in a well drilling the same formation. An example is presented for the well drilled using both technologies.