bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rigless Intervention to Secure Wells with Sustained Annulus Pressure and Tubing Integrity Issues Using Conformance Chemicals on an Unserviceable Platform
Authors: Tiong Yuang Yong , Leong Azemi , Azizan Yusri , Adizamri Rudzaifi , Amilin Khairul 
Published: November 2019

Abstract
An operator in offshore Brunei plans to abandon uneconomical wells that were completed during the 1980s. These wells have sustained annular pressure in the casing, some of which are close to the maximum-allowable annular casing pressure, and require immediate intervention to secure the wells. A rigless operation to isolate the pressure source is required to optimize future abandonment operations using a rig.
Typically, such operations include spotting the cement plug across the perforation using coiled tubing to isolate the pressure source. However, because six of the wells were located below an unserviceable helideck, coiled tubing intervention was not possible, leaving bullheading as the only viable option. The risk associated with bullheading includes the inability to access the end of the production tubing to set an additional mechanical barrier after the cementing operation because of the inability to circulate the well clean. Additional challenges included the unserviceable condition of the pipeline on the platform, which prevents flowback handling, and the lack of crane availability to conduct lifting operations. A small volume of porosity sealant polymer that is lower risk compared to cement slurry was selected to permanently shut off the zone. To overcome the surface limitations, an integrated intervention vessel operation was designed and equipped with fit-for-purpose pumping, flowback, and slickline packages.
After obtaining access to the formation through slickline, treatment was successfully pumped, and the formation sealed off effectively. The slickline mechanical plug was set in the tubing without issue, resulting in each of the wells being safely secured and an estimated 2 weeks of rig time saved for the final abandonment operations. The result marked the first successful operation to secure a well using a small volume of porosity sealant and demonstrated that a similar method and planning can be used to perform future intervention with similar surface conditions and constraints, safely and economically.
Conventional abandonment methods use a coiled tubing unit or rig for intervention. However, an unserviceable helideck restricted access to six of the wells and removing the helideck was not cost effective. This prevented the use of a coiled tubing unit or rig; therefore, bullheading was the only option. Fluid placement during bullheading operations is limited compared to coiled tubing. During the design stage, a small volume of porosity sealant fluid was selected because of the short perforation interval and tight formation.
Achieving Zero Flaring through Oil Tanks Gas Recovery: Case Study from Oman
Authors: Al Kalbani Haitham , Al Marhoobi Faheem , Al Siyabi Hamed , Al Shabibi Saleh , Al Kiyumi Amran 
Published: November 2019

Abstract
The intensity of global warming has increased in recent years and reduction of greenhouse gases become a necessity. The Paris Agreement's recently signed by 196 countries long-term goal is to mitigate the global average temperature to well below 2 °C above pre-industrial levels (Wikipedia, 2018); and to limit the increase to 1.5 °C, as this will results in controlling the risks and effects of climate change. Governments are going towards stringent regulations and implementation of carbon credits.
In oil and gas industry, gas is produced with oil and it is mostly treated and transported for various industrial uses. However, a significant portion of this gas is used in the facilities for power generation and other uses. Tanks for example, are usually blanketed by fuel gas. During the operation of the tanks gases are lost due flashing, level variation and thermal variation. The gases are usually collected in a header and then flared through atmospheric gas flares. The flaring will result in higher CO2 emission. Inefficient flares will also result in incomplete combustion of hydrocarbon and consequently the emission of methane and other gases.
Currently, there are various technologies used to recover the gas, compress it and reuse it. Ejector, Eductor or compressors are mainly used for such application. Depending on the available resources, utilities, operational and maintenance experience and the return on investment any of these technologies can be selected. Daleel Petroleum LLC, who are operating a field in Oman, set a target of zero flaring by initially installing a gas treatment and compression plant to recover associated gas which was successfully commissioned in 2018. The next step is to recover the gas from the tanks, compress it and send to the gas treatment plant for further processing.
This study covers Daleel petroleum LLC's approach in selecting the optimum technology for AP gas recovery and utilization. The study focused on setting the selection criteria and return on investment. A selection criteria will provide other operators with a holistic approach to take decision towards zero flaring and it will set a clear path on how to achieve it.
Completing Ultra Extended-Reach Wells: Overcoming the Torque and Drag Constraints of Brine
Authors: Morrison Alexandra , Serov Nikolay , Fahmy Ahmed 
Published: November 2019

Abstract
The use of invert emulsion drilling fluids as a key enabler to successfully drill extended reach wells and access hydrocarbons that were previously out of reach has been common practice across the industry for decades. One of the more recent, but less frequently discussed, topics is how to effectively design a solids-free, brine-based completion fluid to facilitate the running of the completion by reducing torque and drag.
The choice of lubricant for brine-based completion fluids is primarily driven by technical performance, both in terms of torque reduction and compatibility with the brine, potential brine contaminants, such as divalent ions, invert emulsion drilling fluid, and crude oil that may be encountered in the field.
During the planning phase for a recent ultra-extended-reach drilling campaign located offshore Sakhalin Island, it was highlighted that, without a lubricant in the completion brine, neither the upper nor the lower completion would be able to reach the required total depth, based on historical friction factor data. The brine planned for use as a completion fluid must demonstrate lubricity features near that of an invert-emulsion drilling fluid for the well to be completed successfully.
This paper summarizes the laboratory test results to validate the lubricant selection and provides details about the operational procedures and results achieved after using the new lubricant in the field for the first time.
Lessons Learned from Hydraulic Fracturing the Diyab Shale Gas Wells in UAE
Authors: WU Yang , Newby Warren 
Published: November 2019

Abstract
Since 1st February 2019 Total E&P UAE Unconventional Gas B.V started to operate the Diyab shale gas field in which three horizontal exploration wells had been drilled by ADNOC. Mult- stage hydraulic fracturing treatments were performed on these wells followed by long term well testing to assess the formation potential for a further development.
It was a challenging project since it was the first shale gas frac campaign in UAE where the unconventional reservoir developments are at beginning phase. Various operational problems emerged in wireline pump down, coiled tubing milling and H2S treatment operations, especially during execution in the first well. These operational issues were mainly related to equipment availability and compatibility, personnel competency, logistics support and societal concerns of environment. Corrective measures and innovative designs were conducted to solve the technical issues and improve the operation performance. Good learning curves of different operations were achieved from the first well to the third one.
The lessons learned from this hydraulic fracturing campaign are valuable experience that will be applied to the future pilot wells in Diyab field for the continuous optimization.
Hyper Digressive Screws – The Next Technological Step for Substantial Increase of Efficiency in Twin Screw Multiphase Pumping
Authors: Korte Eike Steffen , Blatt David Johannes , Lewerenz Jörg , Monnickhoff Jeroen Olde , Rohlfing Gerhard 
Published: November 2019

Abstract
Multiphase twin screw pumps are used for delivering gas-liquid-flows even at high gas rates and high differential pressures. In order to match the process conditions regarding pressure and flow the screws, the conveying elements of the pump, can be designed accordingly. The screws are forming enclosed chambers with the surrounding casing and the pitch of those screws is determining the chamber volume and hence the pump flow. To increase pump flow and efficiency digressive screws are known in the oil and gas industry. The next technological step are hyper digressive screws, which are used for the first time in pumps for a Canadian oilfield.
Modelling the Application of Advanced Completion Technology for Improving the Performance of Gas Injection Techniques in Unconventional Oil Reservoirs
Authors: Moradi Mojtaba , Konopczynski Michael , Smith Michael 
Published: November 2019

Abstract
The oil recovery efficiency of unconventional reserves is very low due to their micro-permeability formations and quick depletion of pore pressure near to the fractures and wellbore. Several enhanced oil recovery techniques have been suggested to increase production efficiency in these reservoirs. For example, injection of gas or carbon dioxide in fractured wells, and either producing oil from adjacent wells or back-producing the injected gas and reservoir fluids in the same wellbore after a suitable soaking period (huff & puff). The effective distribution of the injected gas in these wells and the ability to keep gas in the reservoir for maintaining energy and/or having longer contact with interstitial oil can greatly affect the recovery efficiency. This paper describes how the use of advanced completions utilizing passive inflow control devices (ICD) and autonomous inflow control devices (AICD) could significantly improve the performance of EOR process in unconventional oil wells.
ICDs can be installed to balance the distribution of gas injection among the fracture clusters in a horizontal well segmented into multiple compartments at the injection stage while AICDs can restrict the premature production of gas once the wells are at the production stage. Gas flowing through the AICDs device is restricted more than oil. This design prevents excessive production/back-production of gas once the breakthrough happens in one or more compartments.
The application of advanced completions in EOR applications has been studied by the development of an explicit reservoir and well simulation model set up based on reservoir data from an unconventional oil field in North America. A unique hydraulic fracture modelling technique was used in this study to allow the well to be appropriately constructed in the simulation. Also, the impacts of various parameters including the heterogeneities in the reservoir and fracture properties, soaking and production times on the performance of EOR applications were studied. The results show the proper application of advanced well completion can improve huff & puff EOR recovery efficiency by 200% while mitigating the reservoir uncertainties and operational limits and minimising gas injection cost and soaking time in this application.
This paper also shares the experience and lessons learned with prediction models' complexities for the EOR projects in unconventional oil wells and the use of technology.
Role of Automated and Accurate Well Placement in Reducing Subsurface Complexities and Optimizing Geosteering – An Example from Complex Unconventional Reservoirs
Authors: Saikia Kalyan , Shanker Narayan 
Published: November 2019

Abstract
With the increasing demand for hydrocarbons, unconventional reservoirs are gaining prominence and account for a large percentage of oil and gas production. However, these unconventional reservoirs inevitably include challenges that must be carefully managed while planning an extraction strategy to yield maximum recovery. This paper demonstrates the advantages of an integrated and automated well placement workflow to improve geosteering in complex unconventional reservoirs with maximum hydrocarbon recovery.
Automated well placement technique is controlled by three primary components: (1) an integrated asset model; (2) availability of uninterrupted, real-time log data; and (3) appropriately selected well planning methods. Initially, a dynamically updatable model of subsurface geology is created that combines surface topography, and an initial well trajectory is planned. As the well progresses, new log data are added to the asset model, and an interpretation is made in real time. Incorporating real-time data helps to dynamically update the model and enable a comparison of planned vs. actual deviation surveys for course corrections. This procedure guides the geosteerer to update well plans, run feasibility analyses, and predict subsurface uncertainties ahead of drilling, thus, increasing the reservoir penetration and overall well productivity.
Automated well placement while drilling is a relatively new concept and requires collaboration across various disciplines. Currently, such techniques are gaining importance among operators of unconventional resources as it enhances accuracy in well positioning and provides better production while reducing costs, drilling risks, and uncertainties. In addition, when targeting very thin, geologically complex reservoir layers, it provides a holistic view of the dynamically changing asset. The use of this approach will enable oil and gas operators to make collaborative, cross-domain decisions and streamline existing unconventional workflows.
Reshaping Production Logging Execution Workflow Saving Significant Cost and Time for Kuwait Oil Company
Authors: Al-Obaidi Abdulmohsen , Al-Ibrahim Abdullah , Al-Dhafiri Abdulrahman , Al-Mehanna Hamad , Al-Haddad Mohammed , Al-Harbi Sultan , Ayyad Hazim , Mehraj Majid , Abdulrahim Khaled , Hernandez Guillermo 
Published: November 2019

Abstract
Digital Slickline (DSL) Technology for production logging has been successfully implemented in South East Kuwait (SEK) oil fields. This advanced technology enabled Kuwait Oil Company (KOC) to save significant amount of deferred production and operational cost without compromising on the data quality. In addition, it reshaped how the operator performed surveillance operations through a more efficient workflow.
A detailed analysis was carried out in more than 11 wells where production logging was acquired with DSL. Comparing the new workflow to the traditional workflow showed that DSL implementation saved around 51,000 barrels of deferred oil production and improved operational efficiency by 72% compared to the conventional workflow, without compromising on data quality during both real time and interpretation stages.
Based on these results, KOC decided to implement this workflow in majority of the wells and now it has become the standard for production profiling in ESP wells.
From Failure to Opportunity - Unearthing the Unconventional Choices
Authors: Al Awadhi Ibrahim , Sharma Ashok M. , Subramaniam Krishnan 
Published: November 2019

Abstract

Objective/Scope
A localized tube rupture was observed in the convection section of Fired heater. To address this, improve Integrity and avoid Process Safety concerns, the existing convection section required replacement. This paper presents an alternate approach followed to reduce operating costs by enhancing the heater performance and efficiency while addressing high heat flux issue.

Methods, Procedures, Process
The new convection section was designed with an increased coil surface area to enhance the heat recovery and optimize heat flux. Fin materials were changed from original carbon steel to SS410 in high temperature zone to minimize fin burn-off issues. The challenges were phenomenal, as the heater was 40 years old and new convection section is twice heavy and size than existing. In order to overcome, systematic engineering approach was adopted, from sizing new convection section with optimum heat flux, Mechanical design with FEA to verify structure integrity and foundation adequacy for increased loads. As a step toward safeguarding the tube from similar future failure, tube skin thermocouples were installed in shield tubes to facilitate continuous monitoring.

Results, Observations &Conclusions
Analysis confirmed integrity of the heater with minimum modification on anchor bolt avoiding need major foundation and structural upgrade. Two furnaces have been upgraded with new convection section and continuous monitoring for period more than 1 year has confirmed performance with no tube failure ensuring 100% HSE. Post project implementation resulted in more heat recovery from flue gases due to increased. Flue gas temperature leaving convection section was reduced from 450°C to 220°C. Consequently, required fuel gas consumption was reduced considerably by 9031 MT per year for two heaters. In conclusion, similar reductions in fuel gas consumption can be achieved over the equipment's extended service life.
The implementation has led to not only to increase in heater efficiency but in turn improved the heater duty for same burner capacity, there by supporting increase in plant throughput.

Novel/Additive Information
Conventional approach of replacing tube with improved metallurgy would have ensured process safety and structural integrity. However, the synchronized and pre-emptive engineering approach has yielded multiple benefits for the rest of the heater as well plant operational life. This also led to improved efficiency and Optimum Energy Conservation and save operating cost up to almost 1.1Million USD/year. Even a leak can lead us to peak if the opportunity is harvested in right way.
Start-Up & Commissioning Challenges of Sour Gas Injection Compressor Operating in Dense Phase
Authors: Singh Bhupinder , Aggarwal Rajdeep , Singh Harendra , Kamal Faris , Takeidinne Ousama 
Published: November 2019

Abstract
Gas injection compressors are playing major and vital role in oil and gas facilities for maintaining reservoir pressure and sustain production. However, operating experience of these facilities is still limited. Sour and high pressure gas injection compressors present unique challenges especially during start-up/commissioning. Failure of many start-up attempts can cause endless delays and can lead to production and revenue losses. This paper provides useful insights into these issues and their mitigation.
Gas injection compressors operate in very high pressure "Dense Phase" region. Dense phase is compressible fluid and exhibits properties of both liquid and gas. There is no clear boundary separating dense phase from liquid phase or dense phase from gas phase. Slight change in operating conditions can shift the fluid from dense phase to liquid or transition region resulting in unpredictable behavior in compressor/seal system. This can activate spurious shutdown due to either phase change or measurement errors under highly dynamic start-up conditions. Operating range has been studied to identify the issues and mitigation to avoid such conditions.
Detailed root cause analysis has been carried out to investigate full spectrum of operating and startup conditions for compressor as well as dry gas seal system. These are based on author's experience with startup and commissioning of several gas injection compressors which included spurious shutdowns and failure to start up. These have led to development of a robust procedure as well as selection of proper process conditions to successfully start the compressor that include issues such as: Design of dry gas seal system to avoid condensation /sulfur deposition and seal damageScrubber liquid level measurement and controlPotential compressor flooding due to layout and consequent draining issuesShutdown, settle-out and liquid handling during depressurizationPreferred inter stage pressure, temperature and operating region
Start-up and commissioning challenges due to above mentioned design issues have been successfully tested using dynamic simulation and implemented for smooth start-up of an existing gas injection compressor operating in dense phase region.
This paper provides useful insights into issues encountered during start up and commissioning of high pressure gas injection compressor operating in dense phase region and their mitigation. The proposed mitigations have been demonstrated using dynamic simulation and tested at site. Design strategy is provided to ensure more robust design in future for such high pressure gas injection compressor.
Solving the Deccan Trap Drilling Challenge with Innovative Ridged and Conical Diamond Elements Technology
Authors: Sharma Anshul , Narayanan Shine , Zayyan Mohammad , Prakash Shailesh , Raghav Sanjeev , Gounder Shwetha 
Published: November 2019

Abstract
Government of India has set an ambitious target of reducing hydrocarbon import. Increasing oil & gas production is one of the measures by which oil & gas import dependency can be reduced. Despite relatively low crude prices globally, substantial E&P activities have been carried out in the country in the last decade, which has witnessed an exponential increase in exploration of oil and gas reserves. Many new fields were discovered during this exploration campaign out of which, few are potential traps containing hydrocarbons. Kutch and Saurashtra Basin off Gujarat coast is one of the exploration fields that involves trap drilling to explore reservoir sands below. Recently for the very first time, in a decade, oil reserves have been discovered in prospective sedimentary basin of Saurashtra. (DGH India Outlook, 2017-18)
Drilling in this basin is characterized by slow rate of penetration (ROP), frequent bit trips, drill string failure, and high well cost. The 12 1/4-in section in this offshore block typically drills through very hard, abrasive and thick layers of Basaltic formation (known as Deccan Trap) with unconfined compressive strength (UCS) between 18-42 kpsi. Conventional polycrystalline diamond compact (PDC) bits and roller cone (RC) bits faced extreme cutting structure damage and delivered poor ROPs in this section. In this paper, challenges of drilling approximately 2,200 m of hard and abrasive Deccan Trap in the 12.25-in section is discussed along with a proposed solution of hybrid bit design by combining conical (CDE) and ridged (RDE) diamond elements.
Two new hybrid 8-bladed 16-mm bit were specifically designed for this application. The first bit drilled an interval of 952m with an average ROP of 1.9m/hr and the second bit drilled an interval of 960m with an average ROP of 1.83m/hr. Both the bits came out of the hole in good condition, thereby delivering a benchmark performance in drilling this challenging section. The runs resulted in 40% reduction in cost/meter for this section and saved 36 offshore days for the customer.