bluuebunny/crossref_metadata_2025_split huggingface dataset:
Locating and Imaging Leaks Using New Acoustic Array Technology
Authors: Walters Darren , Hill Freeman , Lu Yinghui , Nguyen Nam , Jagannathan Srinivasan , Ang Yi Yang , Reid Joseph 
Published: November 2016

Abstract
With the growing number of mature wells globally, more integrity issues are arising, thus creating a need for diagnostic technologies. Aging wells can develop corrosion or mechanical failures, allowing unwanted communication. Existing technologies allow the identification of leak depths, but do not provide reliable information regarding radial location. A new acoustic array technology helps identify wellbore leaks by depth and radially. A description of the leak's flow pattern in and around the wellbore can also be obtained. Having a clearer picture of the location and leak type makes operational planning more efficient and helps prevent nonproductive time (NPT).
Typically, noise tools have used a single hydrophone or a few sensors to capture noise measurements. An array of sensors can capture an acoustic event from multiple points simultaneously and uses this information to localize the leak. This measurement removes the high dependency on the frequency and magnitude alone to identify the location of a leak. During well testing, sound waves travel up and down the pipe and build standing waves in the pipe, giving a false echo of the leak location when just examining frequency and magnitude. The array negates these inaccuracies and accurately identifies the leak's vertical and radial location, even when frequency and magnitude alone show a different response.
Operators have field tested a new acoustic array tool in aging wells. During this time, the tools were exposed to various leak conditions and problems. The array tools have shown value by identifying depth of communication and the radial location in the wellbore. The radial locater helped discern whether it was tubing, Annuli A, Aannuli B, or an outer casing issue. A unique flow map imaging technology provides a detailed picture of sound-related flow in and around the wellbore.
The new acoustic array technology provides the ability to generate two-dimensional (2D) images of flow-generated noise, which can then be used to extract both leak-depth and radial location. This 2D image is structured to show the makeup of the wellbore and, through a spectrum of color, displays the high flow area where the leak is passing through the tubular section and traveling. The image also identifies where no flow is observed for easy identification of flowing annuli.
Polymer Injection to Rejuvenate a Supermature Oil Field, Polymer Pilot Results, 8 TH Reservoir, Austria
Authors: Clemens Torsten , Kornberger Martin , Lueftenegger Markus 
Published: November 2016

Abstract
The 8 TH reservoir is a "supermature" field which has been in production for more than 65 years. It was waterflooded for more than 50 years resulting in a current water cut of 96 %. The field contains medium viscous oil (in-situ viscosity 19 cP) and hence was considered for polymer injection despite the high water cut which was suggested by some authors to be challenging for polymer injection.
An inverted five spot unconfined polymer injection pilot was performed to reduce the subsurface uncertainties, determine if polymer flooding could lead to incremental oil in "supermature" fields, improve the operating and monitoring capabilities and improve the economic model for full-field implementation.
The results of the pilot show that an increase in 5- 10 % of the recovery factor can be achieved in the pilot area. The reasons for incremental oil production by polymer injection in this "supermature" field are acceleration along high permeable flow paths but more importantly substantial flow diversion in this heterogeneous reservoir. In the pilot area, the highest oil production since 1978 was achieved.
The main uncertainties related to surface handling of the polymer solution prior to injection, injectivity and incremental oil recovery could be reduced by monitoring of various parameters. In particular tracers and molecular weight distribution of polymers were measured to improve the understanding of the polymer solution effects on reservoir performance.
In addition, numerical simulations concerning injectivity and reservoir performance were performed to further improve the understanding of the processes and be able to optimize the operations. The simulations included polymer solution injection induced fractures as well as geological, reservoir fluid/relative permeability and polymer solution property uncertainties and allowed forecasting under uncertainty.
The cost structure of the polymer pilot was used to evaluate full-field economics taking learning curves, upscaling and costs optimisations into account.
EOR by CO2 Emulsions Better Sweep Efficiency and Improved Recovery
Authors: AlOtaibi Fawaz , Zhou Xianmin , Habah Abdulla , Kokal Sunil 
Published: November 2016

Abstract
Carbon dioxide (CO2) flooding projects have shown a large potential for recovering additional oil beyond waterflooding, but in many cases this process is handicapped, especially in thick reservoirs, by CO2 gravity override. Different methods have been used to overcome the CO2 gravity override by either increasing CO2 density, viscosity, or reducing its relative permeability. Reducing the relative permeability of CO2 by the water alternate with gas process has received much experimental and theoretical attention. Although this method helps to control fingering, it also introduces gravity segregation issues. An alternative approach to reduce the mobility is to disperse CO2 as a foam or as an emulsion in a continuous aqueous liquid phase. This paper provides some data and results for a new emulsion system that behaves as a conformance control agent, and also to enhance the recovery of oil following water and CO2 floods.
The CO2 emulsion system used in this study consists of 70 vol% supercritical CO2 (sc-CO2), 30 vol% of water-based polysaccharide linear polymer and a foaming agent (surfactant). This new emulsion system has the ability to be created in situ to provide better mobility control of the injected CO2. Special parallel dual coreflooding experiments were conducted using live oil at reservoir conditions to investigate the effectiveness of the CO2 emulsion system in conformance control and enhancing oil recovery. Several experiments were conducted to explore the effect of the injection rate, injection mode and slug volume on incremental oil recovery using dual core carbonate composite stacks with permeability contrasts up to 60 based on brine permeability.
Results based on this study show the CO2 emulsion's ability to significantly reduce permeability of the higher permeable cores resulting in enhancement of incremental oil recovery from the lower permeable cores. The majority of oil was recovered from the high permeability core during the initial water and CO2 flooding when both cores were placed in parallel. The oil recovery from the low permeable cores by waterflooding was similar to that of the high permeability core, but significantly less during the first CO2 flood. After a slug of CO2 emulsion was injected that blocked the high permeability core, it resulted in 21% incremental oil recovery from the low permeability core during a second CO2 injection. The results demonstrate the improvement in both areal and vertical sweep efficiencies by CO2 emulsions by stabilizing viscous fingering and gravity override issues. The results bode well for scale up for a field trial.
Developed Material Balance Approach for Estimating Gas Initially in Place and Ultimate Recovery for Tight Gas Reservoirs
Authors: Al-Fatlawi Omar , Mofazzal Md Hossain , Hicks Steven , Saeedi Ali 
Published: November 2016

Abstract
The gas material balance equation (MBE) has been widely used as a practical as well as a simple tool to estimate gas initially in place (GIIP), and the ultimate recovery (UR) factor of a gas reservoir. The classical form of the gas material balance equation is developed by considering the reservoir as a simple tank model, in which the relationship between the pressure/gas compressibility factor (p/z) and cumulative gas production (Gp) is generally appeared to be linear. This linear plot is usually extrapolated to estimate GIIP at zero pressure, and UR factor for a given abandonment pressure. While this assumption is reasonable to some extent for conventional reservoirs, this may incur significant error when applied for unconventional tight gas reservoirs. The implementation of multi-tank, compartmented reservoir models are reported to better represent the behaviour of tight gas reservoirs. This study focus to develop a simple numerical method to solve the MBE using the concept of multi-tank, compartmented reservoir model. A simple and practical computational tool is developed by solving the numerical model using False Position iterative method. The tool is applied to calculate GIIP and UR factor for an Australian tight gas field after validation of tool based on history matching. The results demonstrated that the developed tool can be used for the better estimation of GIIP and UR factor with better accuracy. The program can also be used as an efficient tool, especially in the case of homogenous tight gas reservoir, as an alternative to the reservoir simulation to understand the pressure decline behaviour with cumulative gas production; and to estimate GIIP and UR factor.
Multi-Tasking Valve MTV Technology Optimizing Operations for Challenging ICD's Liner Installation in ADMA-OPCO, Abu Dhabi, UAE
Authors: Darceuil Nigel , Mohamed Mohamed El-Sayed , Sabri Abdul Moez , Vicario Roberto , Agilzhanov Nariman , Gharbawi Shihabeldin Mustafa , Musa El-Rasheed , AL-Shamsi Mohamed Khamis , Cortes Wilmer Ferney , Abdelfattah Tarik A. , Pande Nandita , Bamidele Tajudeen 
Published: November 2016

Abstract
Inflow Control Device's (ICD's) are gaining popularity in providing solutions to permeability variance in heterogeneous reservoirs together with water breakthrough occurrences. However, the installation of these devices requires the success of a series of critical operational steps. The MTV feature of the ICD liner allows combination and simplification of these steps ultimately optimizing the installing operation in a challenging ICD liner in ADMA-OPCO.
The installation process essentially requires the top of liner packer to be set followed by zonal isolation packers while allowing the 18 ICD's to be opened after installation. A closed loop for pressure application is needed to set the liner packers consequently requiring a second run for the open pathway in the ICD's. MTV technology allows the ICD to be run in the open position while allowing a closed loop for pressure application therefore saving an extra run, reducing risks and increasing overall operational efficiency.
A single run executed ensured packers were set to secure the liner in place and that there was no requisite for a separate run thus eliminating the risk for the shifting tool to accidentally open/close the ICD's pathway due to a challenging closely spaced liner configuration. Production Logging Tool (PLT) assessment confirmed the objective of equalizing the reservoirs and providing isolation via packers thus allowing a high permeability zone to accept less volume of water was achieved having closely comparable design injectivity targets. Besides zero Non-Productive Time (NPT) for this operation, a recognizable savings was realized both in cost and risk reduction. Extensive multi-disciplinary meetings, several site visits, workshop, risk assessment, excellent communication and on site supervision are the main contributors to the success of this operation. This success encourage the onset of several other wells being pursued using this MTV technology for ICD's in ADMA-OPCO's field.
This MTV technology application has proven its worth as a continuous improvement tool to alleviate previous situations in ADMA-OPCO, thus demonstrating to rise as a pioneer for ICD design. We continue to investigate for our future wells a circulation sub to add additional capability in our ICD liner installation operations.
Inspection of Non-Piggable Piping Using InVista Technology
Authors: Al Jasmi Ashwaq , El Sinnary Omar 
Published: November 2016

Abstract
As a part of GASCO strategy to launch joint initiatives in field testing of latest available NDT technologies with the lowest cost required, and in order to explore the most reliable alternatives in the industry for higher inspection accuracy of non-piggable piping & pipeline with the aim of validating these for future adoption across company's operating sites, GASCO has successfully completed a pilot project using state-of-the-art mini-pigging (InVista technology) for non-piggable pipelines.
The InVista intelligent mini-pigging technology incorporates new high-fidelity ultrasonic probes and provides high accuracy in estimating quantitative wall thickness data vis-à-vis the relatively outdated UT Tethered in-line inspection technology. The InVista technology benefits are summarized as follows; Provides practical solution for non-inspectable pipeline and piping.Achieves higher accuracy in data than the conventional inspection technology.Operates at minimum to no risk and also significantly reduces the downtime of these assets, which is a substantial cost optimizer.Provides a medium to long term perspective for a cost-effective asset integrity management (Cost saving approx.60%).
GASCO performed a pilot project using InVista technology to inspect a non-piggable 8" carbon steel underground fire water line (1.8 Km length) in Buhasa plant, which has never been inspected since 1980.
The InVista inspection results have been confirmed via UT site verification survey for the selected locations where the survey results were matched with the InVista results.
A Specific Approach to Petrophysical Evaluation in a Complex Carbonate Reservoir
Authors: Panda A. , Darous C. , Al-Kindi Z. , Amor F. Ben , Akram A.H. , Kriplani S. 
Published: November 2016

Abstract
The wells of this study have produced from two stacked Carbonate reservoirs which are characterized by variation in interparticle porosity along with a variable secondary porosity system of dissolution from vugs and fractures. The objective was to characterize these heterogeneous reservoirs in the absence of core data and to define consistent petrophysical models including porosity, permeability, rock quality indicators and saturation height models that considers the complexity of the reservoirs to be simulated.
Since no core data is available, the NMR T2 distribution and derived permeability (scaled to mobility from well tests) were correlated with borehole image features in key well to define the rock typing scheme. The saturation height functions were developed directly from the SW from resistivity logs by transforming and adjusting NMR T2 distribution to saturation height. In wells with only conventional logs, the SHF was used to back calculate permeability within the transition zone. In horizontal wells, a layering framework was built using electrical image logs for modeling high conductive features (vugs and fractures).
In the key well, the NMR T2 distribution reveals important variations in pore size distribution that enabled to establish a robust rock typing index based on Lucia Rock Fabric. The permeability estimated from NMR log was adjusted to match mobility from MDT. By transforming the pore size distribution from NMR to saturation height, a close correlation with the SW from resistivity logs is observed. The saturation height function allows within the transition zone to back calculate permeability from log derived SW in wells where NMR log is not available thus capturing heterogeneities in all wells.
For building a 3D property model which can include the layers contributing to dual porosity and permeability, a layer based model was defined in horizontal wells using borehole image dips and textural characteristics, petrophysical interpretation and production data as inputs. The correlation between wells indicate that the shallow most layer shows highest secondary porosity and conductive fractures. Despite the absence of core analysis, limited special logs and a mixture of vertical and horizontal wells with only conventional logs, the petrophysical properties of carbonate reservoirs with complex depositional and diagenetic features can still be established by associating the existing information into a coherent petrophysical model.
The novelty of this study is the construction of consistent permeability and saturation height model for a complex pore network carbonates formation using NMR logs in a key well that honors the log derived saturation profile and allow to back calculate permeability in wells with absence of core and limited log dataset. The construction of detailed layering along horizontal wells based on electrical borehole images is highly beneficial for developing the reservoirs models.
How Safe is the Existing Pipe Rack ? - Gasco Road Map
Authors: Shenoy Manur Ajith , Adel Khalid , Al Awadhi Ibrahim 
Published: November 2016

Abstract
Successive brownfield projects in GASCO plants utilized spare space on existing pipe racks to route new pipes. These pipe racks were originally designed as per erstwhile industry standards and environmental data, which have become obsolete over the years. In the absence of distinct guidelines, indiscriminate approaches were followed to confirm adequacy of these racks in order to reutilize them. Most of these approaches were irrational, had design flaws and raised serious concerns on the safety and integrity of the existing structure. This paper presents the full-fledged methods and procedures followed in GASCO for adequacy check and modifications of structures that assures high level of integrity of existing racks.
Adequacy checks present diverse challenges such as unavailability of as-built documents, want of primary analysis model, revision of codes etc. GASCO has developed an exclusive design guideline for structural adequacy check and execution of modifications, as a consequence of few incidents of failure of old pipe racks. Based on ‘Available' and ‘Not Available' state of required data, the pipe rack is grouped into different categories and stepwise design procedure is outlined for each of the categories. Tips on usage of right codes, estimation of missing loads, elimination of design errors, essential design checks, etc., are supplied. Practical techniques for strengthening of structurally deficient existing members and foundations are elucidated with sketches.
Development and implementation of common guideline encompassing all the design requirements for adequacy check and reinforcement of existing structures has resulted in unifying the approaches across GASCO plants thus ensuring a high level of safety and integrity of the existing pipe racks used in expansion projects.
Broadening the Horizon for Application of Process Safety Tools
Authors: Godfrey Michael John 
Published: November 2016

Abstract
Both Hazard and operability study (HAZOP) and Layer of Protection Analysis (LOPA) are two recognised techniques (or ‘tools') in the Process safety toolkit. Application of these techniques however has historically been restricted to a limited range of operations within upstream. This paper will describe how these tools can, and have been, successfully applied in broader applications.
HAZOP was first applied in the heavy organic chemicals division of Imperial Chemical Industries in 1963. The technique was subsequently developed and matured over the following years. Today in the upstream industry HAZOP is typically applied to both existing process operations and new projects. LOPA generally follows after a HAZOP to perform a semi-quantitative assessment of the event likelihood. Application of these techniques however has historically been restricted to a limited number of operations within upstream. The objectives of the paper are to i) describe examples where HAZOP has been successfully applied to novel operations and activities ii) show how LOPA can be applied, not just for determination of Safety Integrity Level (SIL) but to hazards not associated with an instrumented function and iii) demonstrate that broader application of these tools can lead to and improved understanding of risk and, through effective risk reduction, create value for operating companies.
An overview of potential challenges associated with implementing this adapted approach towards HAZOP is described, but also possible solutions. Following this the links between HAZOP and LOPA, including the information flows from one study to another are re-capped. This includes highlighting the difference between safeguards and layers of protection and qualitative risk assessment (HAZOP) versus semi-quantitative (LOPA). Current triggers for applying LOPA are compared to other approaches that result in a broader perspective and applicability. The key here is to demonstrate that there are a number of additional hazards that may be identified through HAZOP study, but for which an instrumented function may not be provided. As a result these are currently not always taken forward for further, semi-quantitative assessment. This current approach therefore limits our understanding of the associated risk.
In summary, through the use of example scenarios, the paper reveals some of the limitations resulting from restricted application of HAZOP and LOPA. The intent is to raise awareness of how companies are applying these tools to analyse additional operations or activities and, as a result, reduce the frequency of high severity events. The key conclusion is that these existing tools i) with some effort can be readily applied to new / novel areas and ii) can help management understanding of risk and provide assurance that these risks are being adequately managed. In short to fully understand the Process Safety risks associated with our projects and operations we must look to broaden the application of both HAZOP and LOPA tools.