bluuebunny/crossref_metadata_2025_split huggingface dataset:
Best Practices and Challenges for Pipeline Design and Construction in Populated Area
Authors: Nath Nahum Kant , Al Awadhi Ibrahim , Narayanan Sathyanath 
Published: November 2016

Abstract
Pipeline Design and Construction in populated areas to ensure Safety and Integrity of Pipeline System as well as Public Safety in the pipeline vicinity is a major challenge.
GASCO is one of the largest gas processing companies in the world, and it is considered as the major energy and feedstock supplier for the majority of the power, hydrocarbon, and petrochemical industries based in the UAE.
GASCO operates pipelines network having total length of approximately 3,500km, and supplies Sales (fuel) gas to the various consumers such as ADWEA, EMAL, ICAD, UAN Refinery etc. in UAE. GASCO Sales Gas Pipelines pass through populated/industrial/city areas such as Mussafah, Maqta, Yas-Island, Khalifa City, Al Raha and Shahama, etc.
This paper presents the challenges and best practices adopted for Pipeline Design and Construction in GASCO Projects to ensure safety of the people in the vicinity, enhance process safety, improve integrity/reliability of the pipelines, minimize impact on normal operation and maintenance and reduce the risk of business interruption.
Major challenges faced in populated area are the finalization of pipeline route in city area, proper and adequate design to protect the pipeline and subsequently ensuring public safety, minimum impact to the environment, consideration of future developments, construction activities in congested area/ crossings, protection of existing utilities/facilities and third party activities in the vicinity of pipeline.
In GASCO Projects, during pipeline design in populated areas, it is ensured that minimum spacing requirement between pipeline and populated/residential area is as per GASCO Standard Practice, International Standards and QRA recommendations. Selection of Pipeline Location Class/Design Factor, maximum distance requirement between Sectionalizing Valves are complied with Pipeline Codes. Increasing Pipeline cover, Corridor Fencing, Markers and installing slabs for the pipeline protection from third party activities are other measures are taken into an account. The pipeline integrity is enhanced by considering remote operated block valves and pipeline leak detection system, increasing the frequency of Patrolling. Also conducting Pipeline Constructability review to identify the hazards during construction activities is very important. As a proactive approach, future developments in the vicinity of the pipeline is also considered.
GASCO best practices are based on the requirements of Pipeline Codes, International Standards, industry practices, and GASCO Specifications/Standards and experiences from previous pipeline projects.
The Best Practices followed in GASCO projects have ensured the safety of the public and GASCO pipelines for their safe, efficient and reliable operation. Confidence level in assuring integrity of pipelines is boosted. Similar approach will benefit the oil and gas industries for protecting pipelines and ensuring public safety in populated areas.
First Application in Sui Field of Near-Balanced Nitrified Foam Drilling Resulted in Record Drilling Time to Reach TD; in Pakistan – A Case History
Authors: Khalid Ali , Ashraf Qasim , Nusair Mohd. Khair , Luqman Khurram , Shah Rizwan , Ghulam N Agha , Ali Muhammad , Hasan Naveed , Baig Umair A. , Sajjad Muhammad 
Published: November 2016

Abstract
This paper reviews the recently concluded first near balanced nitrified stiff foam drilling application to drill Sui Main Limestone in Sui field Pakistan. The target Sui Main Limestone formation presented numerous drilling challenges in this field. While drilling conventionally total irrecoverable losses were encountered and the resulting loss in head caused the well to kick in. Simultaneously dealing with both these problems resulted in a great amount of NPT, sometimes which extended to a period of months. To address the said problems in an effective and efficient manner, an application of a highly innovative method was considered. Thus a near balanced stiff foam system was designed and found to be highly applicable to drill the Sui Main Limestone formation.
The design of a Near-Balanced Stiff Foam Drilling system (NBD) is first discussed in the paper, which is followed by an overview of the delivered results. While drilling the entire Sui Main Limestone formation no single event of circulation loss was recorded. Also throughout the entire drilling phase "near balanced" conditions were maintained successfully and no influx from the formation was allowed to enter the wellbore. In addition to completing these objectives, another remarkable achievement was that this section was drilled in a record time of 3 days with an average ROP of 14 m/hr while maintaining excellent hole cleaning and no other related drilling problems. In comparison of offset wells where drilling of the same formation would take sometimes up to 3 months, if drilled conventionally.
To sum up, an innovative near balanced stiff foam system was designed to drill the extremely challenging Sui Main Limestone formation. All of the set objectives were delivered to expectations. The operator was able to successfully pass through a cumbersome formation in a record time for this field. This paper elaborates the process used to design a successful near balanced nitrified stiff foam system with applicability for the Sui Main Limestone formation in Sui Field, Baluchistan, Pakistan. The objective of this paper is to highlight all delivered drilling objectives and present lessons learnt while drilling the Sui Main Limestone formation. This will allow for efficient designing of a near balanced stiff foam system for forthcoming wells with similar formations and similar problems.
Estimation of Passive Fire Protection Quantity – A Cost Effective Approach for Offshore Oil & Gas facilities
Authors: Al Ayass Rawad Ghassan , Jha Ajay Nandan , Singh Harendra , Kamal Faris Ragheb , Takieddine Oussama 
Published: November 2016

Abstract
Passive Fire Protection (PFP) is a vital component of fire safety strategy for oil and gas installations. Passive fire protection ensures that relevant structures, piping and equipment or its components have adequate fire resistance with regard to the load bearing properties, integrity and insulation properties during a dimensioning fire event to prevent against escalation of consequences. PFP is generally used for protection of the safety critical systems, maintaining integrity of structures, protection of equipment, barrier walls and floors to provide stability as well as to segregate the plant into areas of manageable risk. It thereby helps in limiting the impact of fire on a facility, safeguards lives of personnel, restricts the growth and spread of fire, allows personnel to escape and offers protection to firefighters.
The applicable Codes & Standards for PFP design are not prescriptive; rather performance based evaluation of the design is required to achieve desired fire safety. This approach, however, does not give unequivocal guidance to designers and can lead to ambiguities and overdesign due to interpretation differences.
In the experience of authors, overdesign of PFP in many cases has had significant domino effects on other aspects of the design such as: Increased space requirement and layouts changesIncreased weight which further impacts structural design particularly on off-shore installationsCost impact and schedule delays during the engineering phasesIncreased installation costAdded cost and complexity to plant inspection & maintenance for the entire operational life
In one such case, it was observed that the incorrect selection of acceptable fire duration and heat flux values resulted in more than double the required quantity of PFP. In another case for an offshore installation, higher heat flux, impairment probability and frequency values were applied for the entire facility, including elevated process facilities that were beyond the range of the jet fires. This resulted in an excessive requirement of PFP leading to weight and space increase as well as difficulties in implementation and project delays.
Based on these as well as other experiences, this paper proposes a structured and cost effective way forward for determining extent and reliable design of PFP while meeting current safety standards. The paper also presents some of the challenges the Contractor has encountered by way of actual case studies to demonstrate the effectiveness of the proposed methodologies for PFP estimation and optimization.
Full Field Chemical EOR in a Mature Southern Alberta Water Flooded Reservoir - The Little Bow Case Study
Authors: Ghedan Shawket G. , Doung Khoi , Kumar Anjani , Card Colin , Ha Helen , Thomson Anne 
Published: November 2016

Abstract
Despite the recent focus on unconventional resources such as shale gas and tight oil in North America, large unrecovered volumes of oil remain in conventional reservoirs making them viable candidates for chemical enhanced oil recovery processes. Replacing or following traditional water flooding with aqueous chemicals that use both surfactant & alkali to reduce interfacial tension and polymer to improve sweep efficiency has been successful in recovering incremental oil from these reservoirs. However, designing the chemical injection scheme is complex, and must be tailored to specific reservoir rock and fluid properties. A strategic design methodology can help provide an optimal, well-performing chemical formulation, even for challenging reservoirs.
Currently, there are around ten Canadian chemical injection projects in operation with the latest being the Little Bow Upper Mannville "I" Pool. An ASP EOR project was initiated in this reservoir in March 2014 in a multiphase development plan. When the project was initiated, Little Bow oil (Phase 1&2) production was around 350 bbl/day. Successful implementation of this project is expected to result in incremental recovery of 5.2 million barrels of oil (12% of the OOIP) over the base waterflood. As of January 2016, 6.648 million barrels of ASP solution has been injected in the reservoir and the field is now showing first signs of incremental production.
This paper presents a workflow that integrates laboratory results, geological and geophysical data and production history into an effective forecasting model. Complex geology and a long production history of the partly depleted Little Bow reservoir have presented a challenge for history matching the primary and water-flood production. Through an iterative process, a full field model was built, history matched, then used as a base case to determine an optimal operational design for the full field.
A multidisciplinary team including geologists, exploitation and reservoir engineers collaborated to develop a 3D geological model and achieve the history match using an iterative approach; resulting in an idealized workflow and a superior history matched model. Using this model and an advanced optimization algorithm, a full field ASP operation design was optimized (based on NPV) for slug sizes, chemical concentrations, pattern design for injection/production wells locations, and drilling & workover locations. The optimized ASP injection scheme is implemented and some field results from January till June 2016 are presented in the paper.
Fugitive Emission Monitoring Program at Dolphin Energy Limited Gas Processing Plant Ras Laffan Qatar
Authors: Atiyeh Rola , Kumar Abhay , Moorthy Dhanaraja 
Published: November 2016

Abstract
One of the key sources of Volatile Organic Compound (VOC) emissions in a natural gas plant are leaks from equipment and pipes known as fugitive emissions. These are unintentional losses due to wear and tear on the facility and manufacturing defects or corrosion. Since 2011, Dolphin Energy has implemented an annual Fugitive Emissions Monitoring (FEM) Program to monitor potential leaking sources from equipment at its onshore Gas Processing Plant in Ras Laffan, Qatar. The objective of this paper is to highlight the progress made through implementation of the FEM Program. The first step of the FEM Program was to identify the process streams handling fluids that contain VOC ten percent by weight or more (&gt;10%) and differentiate among streams handling gases/vapors, light liquids and heavy liquids. To perform its Leak Detection and Repair (LDAR) Program, the company reviewed the inventory of potential leak sources to be included in the Program, then carried out source tagging, monitoring with gas detectors to identify leaks greater than 10,000 ppm, performed leak repairs by maintenance personnel, then conducted further monitoring of repaired leaks and reported on VOC emissions before and after repair. In 2015, The FEM Program covered a total of 82,916 potential sources of leaks out of which 64,983 were accessible and measured for fugitive emissions. Stem control valves were the source-type resulting in most of the leaks above the repair threshold and were the equipment to focus on to reduce significant VOC emissions. This FEM Program has led to an average of 44% reduction in fugitive emissions since the Program started in 2011. Successful implementation of the FEM Program enabled Dolphin Energy to increase its revenue by reducing the fugitive losses, reduce the fire and toxic gas leak risks in the plant, check the integrity of plant equipment, and reduce its carbon footprint on the environment.
Enhance ECD Management Using Sub-Based Uninterrupted Circulating System Application
Authors: Dharma Dion S. , Hidayat Andri M. , Irawan Fikri 
Published: November 2016

Abstract
Bottomhole pressure management is essential to address challenging issues in hostile drilling environmentsbecause of wellbore pressure disparity during pump cycles while in circulating or noncirculating modes. This disparity can cause substantial instability on equivalent circulating density (ECD). While drilling in deepwater, HPHT, or any other hostile environment, these conditions may result in costly nonproductive time, may jeopardize operational safety, or may disrupt the well drillability.
One of the most advanced methods to enhance ECD management during drilling and connection is use of a sub-based uninterrupted circulating system. This technology has been proven to improve drilling performance by maintaining continuous circulation during drilling and connection to retain wellbore pressure stability without significant changes to the rig operation system. This system enables operators to improve drilling performance in wells with a slim pressure window, challenging geomechanical instability, extreme temperature (geothermal), high and long tangent section where hole cleaning is very essential, as well as in extended reach. This system also can be easily integrated with managed pressure drilling technology that exists in the present market.
This system uses a small-footprint, sub-based system with an automated flow switching mechanism to eliminate personnel exposure to the high-pressure system. By maintaining steady state circulation throughout the drilling process, the CFS remedies wellbore pressure disparity to retain continuous circulation and ECD management along the entire wellbore. This condition can effectively assist the operator to reduce nonproductive time, to enhance operational safety, and to enable drilling the well to target depth in a timely and safe manner. This paper will describe the equipment design of this uninterrupted circulating system as well as the best practice and constraints during operation. Generic factory testing will also be discussed to provide comprehensive understanding the reliability of the system.
High-Resolution Reservoir Mapping: From Ultradeep Geosteering Tools to Real-Time Updating of Reservoir Models
Authors: Arata F. , Gangemi G. , Mele M. , Tagliamonte R. L. , Tarchiani C. , Chinellato F. , Denichou J. M. , Maggs D. 
Published: November 2016

Abstract
This paper presents a method for integrating information obtained from ultradeep azimuthal electromagnetic (EM) technology, and processed during geosteering activity, to update a 3D reservoir model.
The latest developments in logging-while-drilling (LWD) technology, unimaginable until a few years ago, dramatically improve understanding reservoir structure far away from the wellbore. Ultradeep azimuthal EM technology provided a step change in remote detection capabilities by mapping resistivity contrasts up to tens of meters away from the wellbore. This innovation helps identify unexpected pay zones while drilling, improves subsurface understanding, and leads to well placement optimization in real time. In addition, the multiboundary reservoir mapping, provided by inversion of the ultradeep azimuthal EM measurements, allows for improvement in 3D reservoir model updates when addressing field development optimization.
The method presented integrates field geological knowledge, wellbore-centric LWD data (logs and images), EM reservoir mapping information, and interpreted seismic data to refine a 3D reservoir model in the neighborhood of the well. The ultimate goal is to include the data acquired in horizontal wells in a live reservoir model update across the entire cycle of the well placement workflow. The process includes a feasibility study for technology and strategy selection, real-time geosteering execution and data integration to update the 3D reservoir model in near real time. Collaborative cross-disciplinary teams, composed of both operator and service company specialists, are focusing more and more of their attention on integrating this information into optimal field development strategy.
Nowadays, it is possible for operators to handle multiboundary reservoir mapping data directly within dedicated geological modeling platforms. Advanced software solutions, designed to improve data accessibility, are the base for new integrated workflows for accurate 3D reservoir models using a multiscale dataset.
A Robust Automatic Dip Picking Technique to Improve Geological Interpretation and Post-Drill Formation Evaluation of Azimuthal Wellbore Image Logs
Authors: Ye Shin-Ju 
Published: November 2016

Abstract
Automatic dip picking avoids the disadvantages of hand picking (subjective, time-consuming, and ergonomically unfriendly); in particular, it reduces dip uncertainty for low-resolution borehole images. Many automatic dip picking methods have been developed since the 1950's. Each of these methods is tied to a specific type of tool (e.g., dipmeter tools or partial-wellbore-coverage pad-type imagers), and they are unreliable to process high-angle and horizontal (HAHz) wellbore azimuthal image data.
This article presents a new method to detect dips in HAHz borehole images. Although this method was originally designed for full wellbore azimuthal images, it is applicable to any dipmeter and pad-type image logs. The proposed automatic dip picking method is simple, yet robust. It consists of the following three main steps: first, determine an optimal sinusoidal trend on the image at each depth using a minimum-variance technique; second, compute the contrast at each depth along the optimal sinusoidal line on the gradient (or first-derivative) image; and finally, locate bedding surface boundaries at depths with the highest contrasts.
This method emulates the human pattern recognition process by first observing overall global image sinusoidal trends, and then examining detailed local bed contrasts to locate the bed boundaries. Conventional pattern fitting methods using edge detection and Hough transform (or sinewave fitting) can be unreliable and greatly affected by the noise and artifacts on the image, as these methods focus immediately on detailed and localized image features, and often overlook global image patterns.
Although other correlation techniques have been tested, the minimum-variance method is the preferred approach, for it generates the most consistent sinewaves. It correlates all azimuthal bins simultaneously and is much more reliable than two-curve correlation methods. Since the variances are calculated along sinusoidal lines, there is no need to perform individual sinewave fitting.
The minimum-variance method combines the conventional, complicated, two-step dipmeter processing methodology (first curve correlation, then sinewave fitting) into one single step to determine an optimal local sinewave. With fewer steps, there are fewer scenarios and problems to consider and fewer parameters to adjust. Moreover, at each depth, the minimum-variance method can find the optimal sinewave within a full range of search parameters (sinusoid amplitude and phase). It can identify faults if visible, as well as reversed sinewaves in "bulls-eye" sections where the wellbore axis is almost parallel to the bedding planes.
The proposed method has been applied to many logging-while-drilling density images and dipmeter data from fields worldwide. It has substantially reduced the interpretational time and dip uncertainty in building earth models from image logs for logging tool response modeling in petrophysical evaluation.
Coupling Production and Injection Systems with Multiple Reservoir Models: A Novel Method of Optimizing Development Strategies in a Mature Giant Oilfield
Authors: Su Shi Jonathan , Patacchini Leonardo , Mohmed Farzeen , Farouk Magdy , Ouzzane Djamel , Draoui Elyes , Torrens Richard , Amoudruz Pierre 
Published: November 2016

Abstract
The building of an integrated asset model for a giant carbonate oil field located offshore Abu Dhabi, consisting of two separate subfields with common production and injection networks, is presented with selected use cases.
Coupling is performed periodically at the wellhead, using a reservoir simulator in which the field manager controls the reservoir models by supplying well constraints and controls the network models by supplying well performance curves. Allocation strategies and pressure and flow constraints are imposed by the field manager, for which the different sub-models are black boxes; the models themselves are controlled hydraulically without embedded production or injection constraints.
This explicit approach has been selected for its flexibility. In particular, by expressing rates at the surface-subsurface interface at standard conditions, it is possible for the two reservoir models to have different equations of state and different treatments of injected water salinity, while the surface models use a black-oil fluid description.
This project required ensuring rate continuity at the transition from history to forecast for over 600 active production and injection strings, even when the reservoir and network models are not perfectly history-matched. This was achieved by introducing pressure shifts in each vertical flow performance curve to ensure continuity of the choking margins (i.e., differences between wellhead pressures and backpressures) and by overriding the default guide rate flow allocation method of the field manager to prevent abrupt changes in the production split of wells currently producing below potential.
The use cases described here are based on an eight-year (2015–2023) drilling schedule followed by no further activity. We focus on assessing the impact on production and injection arising from: replacing pipelines or changing network topologies; relaxing the constraint of producing at initial solution gas-oil ratio with and without reduction of separator pressures; and redistributing or increasing the water injection capacity.