bluuebunny/crossref_metadata_2025_split huggingface dataset:
Underground Blowout Control in Iranian Offshore Oil Field
Authors: Torki Mehdi Abbas , shadravan Arash , Roohi Abbas 
Published: May 2016

Abstract
An underground blowout occurs when formation fluids flow from one subsurface zone to another in an uncontrolled manner. The results range from being indiscernible to catastrophic. An underground blowout can result in minor transfers of fluids that may never be identified or in flow which reaches the sea floor or ground surface. If the flow reaches the surface, a crater, loss of equipment, and sometimes loss of life may result. A major complication in handling underground blowouts is the difficulty in diagnosing what is actually happening in the subsurface. Once an underground blowout is identified, the risk of surface cratering must be considered. Another major difficulty is the lack of a systematic approach to analyzing and controlling the flow. These are aggravated by the relative lack of coverage of underground blowouts in conventional industry well control training. This difficult and complex subject usually accounts for less than 5% of the time or material covered. Overall, it is our opinion that shortcomings exist in all areas relating to underground blowouts: training, prevention, identification, diagnosis, control, and verification of control. An Iranian offshore oil field is located 75 km west of kharg island containing three main production platform AA, AB and AC, with the total capacity of 220000 BPD, each about 80000 BPD. 67 wells out of 107 wells drilled in this oil field, are oil producer now. There are 20 wells on A-11 which produce oil from Ghar and Damam formation. Costly underground blowouts result in mud losses, wasted rig time, often ineffective remediation materials and techniques, and sometimes lost holes, sidetracks, abandoned wells, relief wells, and lost petroleum reserves. The underground blowout can be the most difficult, dangerous, and destructive situation in well control. If the blowout is shallow, cratering can result and endanger the lives of all involved. The underground blowout is often denied since the usual manifestations of a blowout are hidden from view. It is imperative that the blowout be recognized and diagnosed as soon as possible in the early of recent year, while drilling17 1/2" hole of well no. A-11-20, at depth 383m, huge flow of gas was observed and after closing the well, as the formation below shoe was fractured, due to increase pressure to above MASP, gas flowed from seabed, in addition, gas and water flowed from 30" conductor pipe of A-11-17 to lower deck up to 8 meters height. Underground blowout was controlled by engineering planning with no fire after 60 days. It was designed base on three main concepts: Surface blowout control to allow continues work safely on the platform Identify source of gas flow Underground blow out control. In this paper underground blowout control in Abozar oil field will be discussed in detail procedure.
Application of Chelatants in the handling of ASP Produced Fluid
Authors: Cheng Jiecheng , Wu Di , Liu Wenjie , Meng Xiangchun , Sun Fuxiang , Zhao Fengling , Zhao Qiushi , Jiang Neng 
Published: May 2016

Abstract
Suspended solid (SS) particles in the produced water of X2M ASP flooding project were separated by membrane filtration and identified to consist mainly of alkali earth metal carbonates and silica precipitates. A compound formulation of chelatants was developed to stabilize the water phase of ASP flooding produced fluid and prevent or reduce precipitation of both alkali earth metal carbonates and silica. The compound chelatant was put into a limited field trial in the surface production system of X2M ASP flooding project to evaluate its effects on the quality of treated produced water. The averages SS content of treated ASP flooding produced water was decreased to below the 20ppm SS specification limit for re-injection by a dosage of chelatant at 480ppm or above. Scale removal performance of the compound chelatant was also observed during the field trial.

1. Introduction
Alkaline-surfactant-polymer (ASP) flooding has been proven to be a promising recovery method to extract large volume of oil remaining in the ground after conventional oil recovery methods have been implemented. The incremental oil recovery efficiencies of 11 completed ASP flooding field tests ranged from 19 to 34 % of OOIP[1, 2]. ASP flooding is now considered to play an important role in improving the oil recovery and ultimately extending the life of numerous mature reservoirs throughout the world. However, ASP flooding is still facing some major obstacles in produced fluid handling on its way to commercial application. While significant decrease of water-cut of produced liquid and increase of oil production have been achieved, ASP flooding has resulted in tremendous increase of suspended solid (SS) particles in produced fluid, causing great troubles in produced water treatment and re-injection, as well as scale deposition in tubing and surface production facilities[3, 4]. The state-of-art produced water treatment processes such as gravity settling, electrocoagulation, IAF, DAF, biological treatment and bed filtration were not effective enough for the removal of some of the tiny particulate contaminants in the produced water of X2M ASP flooding project. Chemical coagulation and flocculation of ASP flooding produced water was found to be unacceptable due to extremely high dosage, high expense, and disposal of huge amount of toxic sludge[5, 6]. It is thus necessary to search for new treatment methods for ASP flooding produced water based on the sources and characteristics of SS in the troublesome produced water.
Geological Borehole Image Technologies To Unlock Oman's Complex Gas Bearing Amin Formation
Authors: Lawatia Redha , Bildstein Joachim 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
In the northern part of Oman, gas and condensate have been discovered in the Amin formation at depths between 4,000 m and 5,000 m at pressures as low as 450 and more than 600 bar and reservoir temperatures of above 150 degC. The Amin formation is dominated by very heterogeneous Aeolian deposit reservoirs. Due to its age of more than 500 million years and its hard cementation, it poses challenges for the drilling equipment and the development concept. The reservoir reaches a thickness of 200 m and is very stratified with low-quality units: porosity &lt; 5% and permeability &lt; 0.1 mD, and high permeability streaks: porosity &gt; 10% and permeability &gt; 100 mD. Given the complexity and the challenges of this formation, the development started in a promising area with two fields, with good to moderate reservoir quality. At early stage of development, vertical wells were drilled and put into production and only small flow could be achieved without stimulation, leaving considerable hydrocarbon volumes not producible. Then hydraulic frac stimulations have been conducted in them to increase productivity. At 2007 Oman's first horizontal well in this tough rock was drilled. At a vertical depth of 4,033 meter subsea (4,578 meter along hole) the Amin tight sand reservoir was penetrated over a length of almost 400 m within the reservoir. The Image logs confirmed the presence of natural fractures almost perpendicular to the well orientation, which could enhance productivity. Conventional wireline and logging while drilling image logs were acquired to improve the geological understanding of the reservoir complexity. These logs showed important reservoir rock types and geological features such as natural fractures and other features were interpreted; such as type of bedforms that exist in eolian deposits that could correlate to different reservoir rock types and enabled to build geological description along the well, and in- situ stress induced features that indicated the stress concentrations around the wellbore. Production experience from Amin is limited, and there are still big challenges related to the understanding of the reservoir settings and characteristics. The first horizontal well in the deep Amin reservoir is now a major step forward to further developing the challenging Amin formation across the country. It allows exposing more reservoir sections along the horizontal well path to contribute to flow. The results are giving important insights into the lateral heterogeneity of the Amin formation and the existence of natural fracture systems, which could enhance well deliverability. The achieved successes so far from fracturing treatment demonstrate the value of further developing Amin formation.
An Outcrop Analog of Kharaib & Shu'aiba Reservoir: Example of the Urgonian Platform (Lussanenque Area, Gard, SE France)
Authors: Massonnat Gerard Joseph , Pabian-Goyheneche Cecile 
Published: May 2016

ABSTRACT
Pipelines are at risk from external threats including third-party intrusion, societal development and ground movement in addition to the ongoing potential for leaks due to corrosion or other causes. Although the appropriate use of internal inspection practices and regular survey of coating and cathodic protection systems will give timely information on any deterioration in pipeline condition, external threats can be unpredictable.
In this paper we present the unique and innovative pipeline and flowline integrity monitoring system developed by Schlumberger in collaboration with BP. The system uses optical fiber distributed sensors to provide continuous, simultaneous distributed measurements of temperature, strain and vibration for the detection, monitoring, and location of events including:•Third-Party Interference (TPI), including multiple simultaneous disturbances•Geo-hazards for example landslides or subsidence•Gas and oil leaks•Permafrost protection
Optical fiber sensors are widely used and have over the past 20+ years built a track record in the Oil & Gas industry in applications including pipeline condition & leak monitoring, optimization of oil well productivity and LNG plant leak detection and cool-down process monitoring.
The solution provides a unique and proactive approach to pipeline integrity management. It performs analysis of a combination of measurands to provide the pipeline operator with an event recognition and location capability, in effect providing a hazard warning system, and offering the operator the potential to take early action to prevent loss.
Through the use of remote, optically powered amplification, an unprecedented detection range of 100 km is possible without the need for any electronics and therefore remote power along the pipeline. A system can thus monitor 200 km of pipeline when configured to monitor 100 km upstream and downstream from a single location.
Top-of-Line Corrosion Control in Large Diameter Wet Gas Pipelines
Authors: Pugh Dylan , Asher Stefanie , Berchane Nader , Cai Jiyong , Sisak William J. , Pacheco Jorge Luis , Ibrahim Faridah Chee , Wright Eric John , Dhokte Atul , Sunil Venaik , Robson David 
Published: May 2016

Abstract
Large diameter subsea pipelines are being used across the world for wet gas transportation over significant distances from offshore fields to onshore facilities. The ability to predict and control corrosion is necessary to ensure long term integrity of these pipelines. Large diameter wet gas lines operating in stratified flow pose unique challenges for top of the line corrosion which occurs when corrosive gases are found dissolved in condensed water at the top of the pipe. This paper will discuss a study undertaken by ExxonMobil1 and RasGas to establish a mechanistic understanding of sour top of the line corrosion and the operational guidelines developed to control its occurrence.

Introduction
Top-of-the Line (TOL) corrosion can occur in wet gas pipelines operating in stratified flow when low pH water--devoid of inhibitors that are usually present in the bottom of the line fluids--condenses on the upper half of the pipeline causing severe corrosion.
One of the first reported TOL corrosion occurrences dates back to the 1960's at the sour Lacq field in Francei. It occurred in low velocity lines with stratified or stratified-wavy flow regimes. The second reported case was in the sour Crossfield pipelines where again TOL corrosion occurred in lines with low velocities and stratified-wavy flow regimeii. Although the first reported cases of TOL corrosion were in sour fields, sour TOL corrosion has historically been treated as a sweet corrosion phenomenon. Sweet TOL corrosion has been investigated extensively in the literature and several models have been developed to predict its occurrence iii, iv, v, vi, vii. These models are based on the formation of a protective FeCO3 film at the TOL. Sweet TOL corrosion is therefore limited by the amount of iron that can be dissolved in the condensing water. The initial pH of the solution at the TOL will depend on the partial pressure of CO2 and the presence of volatile organic acids in the gas stream. As iron is dissolved in the condensing phase, the pH increases and leads to the possibility of protective iron carbonate formation. At low condensation rate, the accumulation of iron in the TOL solution will increase the pH and result in the formation of protective iron carbonate scale. At high condensation rates, the dissolved iron is continuously removed. This leads to a lower TOL solution pH and instability of iron carbonate scale, resulting in higher TOL corrosion rate. Thus, in sweet systems a critical condensation rate can be predicted below which TOL corrosion should not be significant. The critical condensation rate has been estimated to be between 0.15 g/m2s and 0.25 g/m2s viii.
When Polymer-based Acids can be used? A Core Flood Study
Authors: Gomaa Ahmed Mohamed , mahmoud mohamed , Nasr-El-Din Hisham A. 
Published: May 2016

Abstract
In-situ gelled acids that are based on polymers have been used in the field for several years, and were the subject of many lab studies. An extensive literature survey reveals that there are conflicting opinions about using these acids. On one hand, these acids were used in the field, with mixed results. Recent lab work indicated that these acids can cause damage under certain conditions. There is no agreement on when this system can be successfully applied in the field.
A core flood study was conducted using Indiana limestone cores (1.5 in. diameter & 20 in. long) at high temperatures and pressures. Propagation of the acid, polymer, and cross-linker inside the long cores was examined for the first time in detail. Samples of the core effluent were collected and the concentrations of calcium, cross-linker, and acid were measured. Permeability enhancement and location of any precipitation was detected using CT scanner to the core after, and before the acid injection. Different sections were cut from the core to investigate the propagation, and precipitation of polymer and cross-linker. Material balance was conducted to determine the amounts of cross-liker that retained in the core.
Experimental results show that this acid system caused damage in some cases. At low shear rates, in-situ gelled acid formed a gel inside the core, as indicated by the cyclic behavior noted in the pressure drop across the core, and the acid changed direction inside the core several times. However, this gel significantly reduced the core permeability. At high shear rates, a smaller amount of gel was formed inside the core and the acid did change its direction inside the core. A significant permeability enhancement was achieved. Wormhole length increased as the shear rate was increased, while the diameter of wormhole increased as the cumulative injected volume of acid was increased. CT scan indicated the presence of gel residue inside the and around the worm hole. Gel residue increased at low shear rates. Material balance on the cross-linker indicated that a significant amount of the cross-linker was retained in the core. This amount increased at low shear rates.
Effects of Regional Charge History and PVT Conditions over Geologic Timescales on Local Refined Reservoir-Scale Models, Using a Petroleum Systems Modeling Approach
Authors: Derks Jan Frederik , Swientek Oliver , Fuchs Thomas , Kauerauf Armin , Al Saeed Mariam , Al Hajeri Mubarak M.A.H. 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
Herein we present a method of linking a regional charge model to a high-resolution prospect scale model including detailed geometry descriptions. The presented link includes full PVT controlled charge modeling from the regional- to the local high-resolution model. Our basin modeling workflow is combined with a detailed reservoir description, including geological-, geophysical- and geochemical information in an integrated approach on prospect scale. Pressure and temperature development through geologic time within the reservoir can now be modeled in more detail and re-migration within the reservoir can be described in much higher resolution without losing regional information that is not covered by the prospect scale model. The application of this approach in basin modeling is presented and examples are given where the linking of models with different resolutions is used to describe a well-explored petroleum system including migration more accurately. Over geologic timescales, the modeling of reservoir-scale features and processes are limited by the resolution of basin-scale petroleum system models. Maturation of source rocks and migration is normally described on scales of kilometers. On the other hand reservoir models cannot describe processes on geologic timescales leading to conditions before start of production. Linking a regional-scale basin model describing the charge of a petroleum system including migration to the prospect/field and a high-resolution geologic model on reservoir-scale describing the geometries and litho-properties of the reservoirs can help to solve this problem. In order to explain small-scale processes in reservoirs in oil provinces, knowledge of the geologic history of the reservoirs and respective petroleum system elements is needed. In particular the reconstruction of pre-production PVT-conditions and charge timing of a reservoir are of high importance to understand the reservoir system. The description of reservoir-scale features caused by processes over geologic time provides important information for improved production and long-term extraction strategies.
Zero-Gen Campuses Development In India - A Sustainable Promise Made To The Society
Authors: Bammidi Vidya Sagar , Rao Aradhana , Sharma Pratik 
Published: May 2016

Abstract
One of the issues which is of highest importance to developing countries is reducing the vulnerability of their natural and socio-economic systems to the projected climate change. India and other developing countries are facing the challenge of promoting mitigation and adaptation strategies for economic development. The most effective way to address climate change is to adopt a sustainable development pathway by shifting to environmentally sustainable technologies and promotion of energy efficiency, renewable energy, forest conservation, reforestation, water conservation, etc.
The paper looks into proper management of ?Energy Life Cycle? in a society by developing the Zero-Gen campuses that keeps the mother Earth healthy. The life's endurance on the energy resources should quickly be brought to light and the principles should be followed under sustainable guidance. Zero waste, Zero Emissions, Zero risk hazards, etc contribute to Zero-Gen.
People/ Organizations/Companies with a vision of ?Co-creation of wealth & sharing it with the society? strive towards this kind of strategic development. The thirst of a zero-gen campus has made the need for water resources management, e-waste management, energy management strategies, paper management, and green belt implementation and mainly zero risk management system.
Zero-Gen Campuses of various types and sizes in many regions of the country should set examples which make the people feel environmentally responsible. One of the best strategies to improve the environmental forecast is education and awareness. To bring in this awareness companies should set themselves as examples by following the norms. This paper addresses the challenges of sustainable development of offices or campuses with the implementation of the strategies from the best practices benchmarked in a case study.
The case study showcases the external challenges, business implications and some forecasting that effect the climate change.
Permanent Downhole Cable to Surface Gauges Technology and Real-time Monitoring System Optimizes Artificial Lift Wells Production Operations, B-Field Sultanate of Oman Case Study
Authors: Mirza Muhammad , Soegiyono Rini Eka A , Syaifudin Ahmad , Al Habsi Said Amor , ElSherif Tamer Ahmed 
Published: May 2016

Abstract
The principal considerations in designing a permanent gauge system are the accuracy, resolution and stability of the acquired data (pressure, temperature, flow) and the reliability with which this data can be transmitted to the end user. Cable to Surface gauges combined with the ISU, or ISP Unit can immediately satisfy metrological requirements for pressure and temperature data acquisition in real-time.
Set against the industry demand, especially during the economic downturn, the objective of permanent downhole monitoring gauges with Cable to Surface (CTS) technology deployment is to optimize production and boost average recovery rates using a cost effective fit for purpose real-time monitoring system that involves technology (tools), people and process.
The B-Field was discovered in 1991 by exploration well B-01. Twelve wells have been drilled since then and started producing oil in 1994 from one vertical well and the rest are horizontal wells. There is no injection well in this field. Based on a simulation study for an optimum infill drilling case, oil rate is predicted to increase by three folds in 2009, with a recovery factor is estimated to reach 17.2 % of its original oil in place by year 2026.
This paper will describe applications and technical contribution of permanent downhole monitoring gauges using Cable to Surface technology digitally enabled with built-in sensors and linked to personnel with diagnostic and remediation skills, resulted pro-active measures and actions to improve equipment run life and well performance, as well as assist in reservoir management decision making. Examples include the use, methods and two field cases of the technology and system application in BM-17 progressive cavity pump (PCP) and BM-18 beam pump wells. Observation to the rest of the wells in this field is continuously performed to gain values from real-time optimization by reducing operating cost and restoring oil production.