bluuebunny/crossref_metadata_2025_split huggingface dataset:
Introducing Data-Driven Virtual Viscosity Measurements
Authors: Karpan Volodimir , Al Farsi Samya , Al Sulaimani Hanaa , Al Mahrouqi Dawood , Al Mjeni Rifaat , van Batenburg Diederik 
Published: October 2022

AbstractPolymer-based chemical flooding is a mature enhanced oil recovery technology that has proven to result in significant incremental oil recovery that is both cost and GHG emission-competitive compared to the oil recovered by conventional waterflooding. For such chemical flooding projects, controlling the viscosity of injected polymer solution is critical because the polymer cost is one of the most significant cost elements in the project economics. The polymer viscosity is routinely measured in the laboratory using fluid samples taken manually at different sampling points (i.e., polymer preparation facilities, injecting lines, and well heads). However, in the case of large-scale projects, such viscosity monitoring becomes time-consuming and requires dedicated field staff. Moreover, the quality of laboratory-measured viscosity is questionable due to the potential viscosity degradation caused by the oxygen ingress or polymer shearing during sampling, storage, and measurement. The inline viscometers were introduced to improve the reliability of viscosity measurements and have a better quality of viscosity monitoring. Such viscometers are relatively simple devices readily available on the market from several vendors. However, the device comes at additional costs and requires modifications at the tie-in point (bypass line, drainage, and (sometimes) communication and power lines). On top of it, operational costs include regular maintenance that the inline viscometer requires to ensure good data quality.This study introduces a data-driven Virtual Viscosity Meter (VVM) as a tool to augment the inline and laboratory viscosity measurements. Standard injector wells in a field are equipped with gauges that report injection rate, well/tubing head pressure, and temperature of the injected fluid. With such well data and viscosity measurements, calculating the viscosity becomes a machine learning regression problem. Training the machine learning regression methods on the actual inline and laboratory-measured polymer viscosity has demonstrated that VVM is a promising, high-accuracy solution with a low computational cost. The possibility of further implementing this approach to calculate the viscosity of an injected fluid was investigated using the data from several projects. Finally, the application of the VVM tool for viscosity monitoring and the limitations of VVM were discussed.
Record Setting Casing Run-In Speed Attributed to Significant Surge Reduction System Tailored for Deepwater HP/HT Operation in India
Authors: Gupta Shruti , Dange Mikhil , Missiaen Francois , Kumar Animesh 
Published: October 2022

Abstract
A major operator drilling in the Krishna-Godavari (KG) basin faced challenges attributed to tight tolerance and severe losses while running-in casing in deepwater conditions. The operator initially spent up to five days of rig time filling the casing conventionally and reducing running speeds to reach the planned depth.
To help mitigate severe losses and high surge pressure caused by tight tolerance in the wellbore, the operator had to reduce the running speed and use high quantities of lost-circulation material (LCM), which caused premature conversion of float equipment from autofill mode to conventional mode (closed-ended pipe) midway, resulting in longer casing run-in time. Surge and swab analysis was conducted to validate equivalent circulating density (ECD) reduction during the casing run and derive a program of operation to safely optimize the casing run.
The surge reduction float equipment package, comprised of a retained flapper valve and ball activation system, allowed the casing to autofill through large flow by areas, tolerant to the LCM in the well, while maintaining compatibility with the subsurface release plug system necessary for deepwater operations. The system allowed for midway circulation, as necessary, to help ensure the fluid level could be maintained during the casing run. The surge reduction equipment set was the first of its kind and consisted of three flapper valves distributed between the float collar and float shoe to provide the necessary redundancy to combat issues with the floats not holding because of the harsh conditions of the operation. It allowed casing to be run at optimum speed and remain within the pore pressure and fracture gradient window. A single deactivation ball installed in the float collar helped ensure the conversion of all valves in both the collar and shoe at the set flow rate, once reaching the planned casing shoe depth. This system combined with high LCM compatible subsurface plug sets not only induced zero losses while performing run in hole (RIH) casing operations (enabling 400% increased casing running speed), it also ensured consistent shoe track integrity with no float valve failure and no wet shoe; this saved several days of deepwater rig time for the operator.
The first ever successful deployment of surge reduction float equipment with a subsurface release plug system in India is discussed, which reduced casing run-in time by up to 22 hours.
Reducing Drilling Risk in Extremely Sour Formations with Novel Scavenger in a Clay Free Non-Aqueous Fluid System
Authors: Nasrallah Mena , Spagnolo Salvatore , Giubertoni Matteo , De Bonis Emanuele , Cavagnero Giovanni , Hafez Mohamed 
Published: October 2022

Abstract
This paper discusses how an organophilic clay-free invert emulsion fluid (OCF-IEF) was customized with a fast-acting hydrogen sulfide (H2S) scavenger to drill a high temperature (HT) exploration well offshore UAE with high H2S concentrations. This application was the first in country to drill through a high H2S formation using an invert emulsion fluid maintaining all parameters within required specifications setting new drilling performance limits.
Exploratory HT wells are associated with notable challenges requiring extensive fluid design and qualification. The additional risk of mitigating high H2S was a key consideration in the fluid design phase. A specialized H2S scavenger was selected based on its fast reaction rates proven through testing. The drilling fluid rheology profile and hydraulics were optimized for HTHP drilling conditions, with the fragile gel structure providing adequate suspension while minimizing pressures running the liner. This paper discusses the design approach to fluid customization in the planning phase and procedures followed during execution ensuring trouble-free performance managing the high H2S risk while drilling an HT Exploration well.
Proper planning and execution, using best-available drilling practices, enabled drilling of this record-breaking well without encountering significant issues that could impact rig time and increase costs. The fast-acting H2S scavenger ensured no acidic gas detection on surface throughout drilling the section, confirmed through continuous Garett Gas Train (GGT) testing on site proving no traces of the acidic gases were left untreated. This fact was confirmed through pressure, volume and temperature (PVT) sampling showing the formation drilled contained 33% H2S. The section was drilled with constant background H2S and CO2 as well as hydrocarbon gas presence and was left open for 82 days with high percentages of gas at every bottoms up. Despite this, no H2S was recorded at surface. The OCF-IEF was subjected to several static periods of up to 145 hours at temperatures between 337°F and 390°F with superior fluid stability which saved on tripping time to condition the fluid prior to logging. Proper planning and risk mitigation were key in the success of this application. The OCF-IEF system proved to be a key success factor in delivering this critical interval due to the narrow clearance while running casing, preventing any surge or swab effects.
The specifically designed OCF-IEF including a fast-acting H2S scavenger displayed superior performance in treating out the acidic gases compared to other scavengers on the market and brought innovation to reality, treating H2S concentrations greater than 33% v/v with no gas released on surface. Successful deployment of this technology in such a challenging environment provides confidence in planning future exploration wells.
15 Years of Foamed Cementing in Oman: Future Applications and Lessons Learned from 270+ Foamed Cementing Operations
Authors: Al Sulaimi Zahra , Al Adhali Sara , Austin Jamie 
Published: October 2022

Abstract
For more than 15 years, foamed cementing has been deployed on wells drilled in the Fahud and Natih fields of North Oman. The production section targets the Natih formation, a fractured Mesozoic hydrocarbon-bearing carbonate sealed by the Fiqa above and the Nahr Umr shale below. The Natih carbonate characteristically requires a cementing design to cure losses while providing zonal isolation. Foamed cement is the standardized cement design used to meet this objective.
Previous attempts to mitigate lost circulation during cement placement using conventional lost-circulation materials were attempted with little success. Since 2006, the advent of foamed cementing has been prescribed as the standard design for cement placement across the 8 1/2-in. production section. These wells have experienced an evolution of stage tools as well as liner packers to aid isolation. The cementing operation consists of a decision tree design approach based on the tools used on the 9 5/8-in. section as well as the quality of wellbore returns observed during cement delivery. The initial stage consists of nitrified water with a foaming agent intended to reduce the hydrostatic burden observed on the fractured formations. This is followed by a four-stage "filler" of foam cement, each with a specific nitrogen rate necessary to maintain the designed density at the final placement depth. If wellbore returns are stable throughout the "filler" phase, the nitrogen rate is reduced to target an ideal final cement density to help ensure the cement sheath has optimized sealant capabilities across the section objective. If wellbore returns are unstable, the final nitrogen stages are maintained, and emphasis is placed on finalizing displacement and choking the backside, as necessary, to maintain foam expansion.
Approximately 270 foamed cement applications were executed in the field using this approach. The acceptance criteria target for this section is for returns to be observed at the surface during cement displacement before packer installation. Continuous lessons learned on design parameters necessary to achieve the objective were captured in the 15-year period discussed. The value added using stage tools versus liner packers was measured and the base slurry designed used for the foam has been modified over time to deliver the highest probability of success for these wells.
Designed cement properties were evaluated and optimized over the 15-year period of foamed cement delivery. Improvement to cement hydration analysis (CHA), permeability, transition time, and expansion slurry properties are discussed.
Additionally discussed, as losses continue to be challenging across these sections, a variation of 11-kPa/m ultra-lightweight foamed slurry designed for wells in the Fahud and Natih production sections are an alternative option for extreme losses observed at &gt; 5 m3/hr before cementing.
A Novel Cement Additive to Prevent Gas Migration in Producing and Abandoned Oil and Gas Wells
Authors: Mohamed Abdelmjeed , Giovannetti Bruno , Salehi Saeed , Muhammed Farag 
Published: October 2022

AbstractGas leakages from producing and abandoned oil and gas wells are considered a threat to the environment and increase greenhouse gas emissions. They are also a cause of sustained casing pressure and other wellbore integrity problems, which are significant operational and safety issues. Cement integrity in oil and gas wells is crucial to ensure excellent zonal isolation and prevent gas migration to the surface over a long production time. Therefore, cement slurry should be carefully designed to yield better performance in sealing the annulus between the casing and drilled formations. This study introduces a novel additive to improve the cement slurry properties and mitigate the gas migration problem.The new cement formulation consists of water, dispersant, retarder, cement (class G), and a novel polymeric anti-gas migration additive. To evaluate the performance of the new additive, several formulations were prepared by varying the additive concentrations from 0 to 6.0% by weight of cement (BWOC). The mixing process was first optimized to fulfill better slurry performance. The effect of the new additive on static gel strength (SGS), gas migration, slurry rheology, fluid loss, consistency, thickening time, and unconfined compressive strength (UCS) was studied at 70°C and 90°C. Static gel strength was the primary indicator of cement slurry's ability to resist gas migration; therefore, it was initially used to optimize the additive concentration. Eventually, the optimized formulation was tested on a new experimental pipe setup to simulate the actual well conditions.The SGS results showed that the new additive could effectively reduce the gas transition time to 15-25 minutes for the optimum concentration, compared to around 50 min for the base cement. The optimum concentration was found in the range of 1.5-3% BWOC. Adding more than this concentration would increase the cementing operation cost without further improving the performance. Consistency and rheological measurements confirmed the excellent stability and pumpability of the new cement slurry with this concentration range. The new additive performed better with increasing temperature up to the maximum testing temperature, 90°C. A high reduction in the fluid loss was also observed with the introduced additive compared to base cement slurry and other commercial additives. Pipe test results showed that the new additive completely stopped gas migration, and no gas leakage was observed for more than 24 hrs. In contrast, a high leakage rate was observed with the base cement after only 4-6 hrs.The findings of this study are promising. Adding 1.5-3.0% BWOC of the new additive was adequate to maintain cement slurry expansion and develop enough static gel strength in a short time. Using the introduced cement formulation with more optimization to the cementing operation would significantly improve wellbore integrity for short-term and long-term operations.
Hollow Bit: The First Worldwide Campaign Result of a Breakthrough Technology of Slot Recovery Technique in Offshore Abu Dhabi Field
Authors: Fukuda Kengo , Biyanni Hanifan Mayo , Toma Motohiro , Moslim Samaawi Moslim , Toki Takahiro , Al Zaabi Ali Yousef , Najjar Abdelrahman , Chammout Omar 
Published: October 2022

Abstract
Demands for reutilizing existing slots on the offshore platform are expected to rise to maintain oil and gas productivity by drilling and completing the well to different targets, whereas most of the slots are occupied in mature fields. Slot recovery operations are one of the solutions to recover occupied slots. Different slot recovery techniques have been executed in the Offshore Abu Dhabi field, which include cut & pull, milling, Casing Pulling Tool, and Conductor Deflector Tool techniques which are time-consuming and require high overpull to release the casings. The hollow bit is a slot recovery technique that enables the user to recover casing by the standard fishing tool (i.e., casing spear and overshot) without excessive overpull which inherits a risk of surface equipment damage and safety issues on the rig floor. Moreover, overcoming the strong cement bonding between a 30" conductor and 13-3/8" casing is difficult and is dependent on the cement condition. The casing is cut into short intervals to be pulled out which results in a long operation duration. Hollow bit removes the annulus cement between 30" conductor pipe and 13-3/8" casing by washing over the cement. Casing cuts can be minimized since the removal of cement from the annulus overcomes the cement condition uncertainties which results in a shorter slot recovery duration.
This paper presents the 3 hollow bit field trials conducted in 2021-2022 in Offshore Abu Dhabi. Lessons learned accumulated from each trial were implemented in subsequent wells to improve the performance. Performance was increased by 60% compared to other slot recovery methods by reducing the operation duration from 20.8 days to 12.5 days. Best practices that can be implemented to similar application by hollow bit are also presented.
Latest Generation Flat Rheology Fluid Enables Successful Drilling at High Overbalance Conditions Utilizing Multi-Functional Nanoscale Additive
Authors: Olivares Tulio , Pino Rafael , Rojas Juan Carlos , Cascone Alessandro 
Published: October 2022

Abstract
Drilling for Oil & Gas is never an easy task. In order to reach to the hydrocarbon source, several layers of drilling formations with different characteristics need to be drilled through. This leads to a challenge of needing various well designs, tools and fluids to drill these wells. An ideal case would a fluid design that is flexible enough to be applicable for most of the fields; yet providing consistent properties across a wide range of temperatures and pressures. A uniquely customizable flat rheology fluid was developed to meet a variety of conditions in terms of pressures from low density to high density to maintain well control and temperatures from 60 °F at surface to 150 °F - 400 °F range downhole. The fluid constituents were carefully selected to exhibit a flat rheology profile to aid in trouble-free drilling of the well. The fluid also used a novel nanoscale additive to aid in filtration control to enhance filter cake properties in high overbalance situations and minimize the risk of differential sticking which is a large contributor of NPT in drilling operations. The fluid properties were then optimized with typical drilling parameters and well conditions in a robust physics-based hydraulics simulator to ensure successful execution and anticipation of various scenarios. After vetting various formulations in a laboratory setting designed to mimic downhole conditions including contaminants like acid gases; the fluid was ready to be utilized to drill a well in onshore. A holistic plan was utilized to manage all project aspects from resources, logistics, procedures and what if scenarios to allow for a successful implementation of the fluid.
The two intervals were drilled ahead of schedule with no NPT or unscheduled events, such as losses or differential sticking despite the fact that one of the intervals had high overbalance of 5,700 psi over the pore pressure. The fluid’s properties were tracked across various temperatures to understand the fluid behavior at different sections of the well where it showed consistently flat rheological profile.
The hydraulics simulations showed superior hole cleaning conditions as well as the ability to stay within the narrow drilling window which was confirmed by the trip conditions with no back-reaming and not inducing fractures or experiencing any downhole losses. The fluid performance and consistent fluid properties including rheology, filtration control and suspension of cuttings and weight material with no sag occurrences were enabled by using novel emulsifier chemistry, customized polymeric additives and a novel multi-functional nanoscale additive for high overbalance conditions.
A New Application of Pressure Transient Analysis to Calculate Completion Efficiency in Long Horizontal Wells with Limited Entries: Flow Restrictions and Well Architecture
Authors: Al Qahtani Abdullah M. , Al Qahtan Bader A. 
Published: October 2022

Abstract
This paper presents a novel application of pressure transient analysis to calculate completion efficiency in long horizontal wells with limited entries to calculate completion efficiency in long horizontal wells, using pressure transient analysis to unleash flow efficiency restrictions and maximize well productivity. This calculation scheme could be done prior to well drilling using reservoir data and calculating unsteady flow pressure perturbation around flow ingresses, using Green's functions, or during production modes at any time using downhole pressure transient behavior at each flow restriction. The total flow efficiency is impacted by the configuration of well architecture and the distribution of flow entries along horizontal sections and laterals. The unsteady flow pressure perturbation could be augmented into the wellbore flow hydraulics to determine the overall performance of wells, especially in finite-conductivity horizontal and multilateral wells. The use of pressure transient analysis showed a very instrumental tool to calculate the overall efficiency of completion in horizontal wells. It can explain why some horizontal wells didn't produce to the design capacity and help salvage well completion design. This advanced calculation scheme has never been used as a tool to calculate a completion efficiency factor by which the overall all performance of horizontal wells are measured. The scheme is an innovative way to design and maximize well completion to decide on the configuration of well architecture and placement of flow entries/restrictions in horizontal sections. This is best applied during production mode to continuously monitoring completion efficiencies in cases where multiphase flow occurs, with real-time data acquisition of pressure transient downhole.
Maximizing Reserves Value Using Multilateral Wells - A Decision Support Tool and Key Applications
Authors: Yanez Eglier , Saputelli Luigi , Al Hosani Fahad 
Published: October 2022

AbstractAs global energy market conditions demand more reliable energy sources, fields with lower productivity reservoirs struggle to provide cost-effective production options. Multilateral technology (MLT) has been used to improve per-well deliverability and economics, i.e., by increasing the drainage area with less surface footprint.The objective of this work is to review the state-of-the-art of selected completions to provide insights for adoption of MLT technologies including lessons learnt, experiences and some recommendations. Six globally selected demonstrative applications were reviewed to validate the technical assumptions for selecting a particular MLT concept.The first step was to review earlier applications in similar formations to identify the degree of success of these wells and to research possible better candidate reservoirs. Secondly, a screening tool analyzes specific reservoir production conditions where the application of MLT would be compelling. The research was focused on reservoirs with noticeable high-economic potential interest in the application of such technologies.We propose a workflow combining both technical and economic criteria to guide the selection of MLT vs single lateral wells, providing a cost-effective and lower risk decision support tool. We introduced a process to identify the MLT applicability window based on the Activation Index (AI) and the mother to Lateral cost ratio. Our proposed method is likely to be beneficial for operators which struggle to make smart decisions on MLT well concept selection.We show that MLT completions can reduce between 10 and 30% the D&C cost requirements while enhancing field development NPV in the range of 1-21%, and with the potential of promoting fields that were otherwise uneconomic. We discuss here the success factors to make this possible. In addition, one key advantage of MLT is the acceleration of production since multiple zones are available for production much earlier compared to the single zone wells. Furthermore, the implementation of MLT completions is enabling the recovery of reserves on fields where the surface space is constrained due to either a high number of wells or a geographic limitation or even a combination of both.