bluuebunny/crossref_metadata_2025_split huggingface dataset:
Smart Field Deployment - Towards the Appropriate Level of Smartness
Authors: Engbers Peter , Male Peter , Chai Chon Fui 
Published: March 2015

Abstract
Smart Fields solutions add a lot of value to further field development and well, reservoir, and facility management. Over the years, Shell has developed and deployed many integrated Smart Fields solutions. However, as each field is different, with more complex field development types, ‘stacking’ of different solutions is becoming common, we need to ensure that we identify and deploy the right balance of solutions. The "Appropriate Level of Smartness" (ALoS) describes the desired stage. The focus of the Smart Fields programme has therefore shifted from "selling" individual solutions to achieving ALoS in all our key projects (help assets know and implement the balanced mix of solutions).
In this paper, we describe how we screen, decide applicability, and deploy Smart Field solutions for the Shell portfolio. The screening identifies the relevant Smart Fields Solutions for a project or asset that will maximize the project value and help reduce its key business uncertainties, taking a full lifecycle view. Deployment will help projects to ensure that the value opportunities identified through the Screening are materialized into solutions deployed at the asset, realizing the value to Shell. Solutions need to be tailored for the specific field, production type, purpose, or environment (Archetype). We have developed a framework to ensure that we deploy the right Smart Field solutions for each type of field and asset. As guidance, we make use of a newly built Solutions Advisory. This advisory, for example, highlights which solutions are standard in which environment, meaning that you would have to justify why not to implement.
At the end, we will show how Smart Fields has already added substantial value in brownfields, whilst ALoS guarantees our future value and effectiveness of greenfield projects, ensuring that we do it right from the beginning, so no retrofitting is required.
3D Broadband Multi-Azimuth Survey - Seismic Technology for the Complex M Field
Authors: Balakrishnan Gopikrishnan , Nayak Prasanta , Tarigan Rudhy L. 
Published: March 2015

Abstract

I. Introduction
The M Field, located in 500–600m of waterdepth in offshore Sabah, Malaysia, was discovered in 2004. In 2012, Shell took Final Investment Decision (FID) on the project which will include drilling of several producers and water injectors, with production via a Tension Leg Platform (TLP). The main reservoirs of the M field are the K-1 and K-2 sands; both are located at relatively shallow depths below mudline. They are structurally complex, significantly compartmentalized and underlie a complex overburden with presence of gas. To improve reservoir and structural mapping for well positioning and well planning, a Multi-AZimuth (MAZ) broadband 3D survey was carried out over the field. A fast track Post Stack Time Migration (PoSTM) datasets was delivered three months after the last shot of the survey which was critical for geohazards interpretation for top hole well trajectories. A Pre Stack Time Migration (PSTM) volume was delivered after five months from the last shot and a final Pre Stack Depth Migration (PSDM) is expected in August for the structural interpretation and reservoir characterization at the reservoir level.

II. Geophysical Challenges
The imaging challenges at the M Field are caused by the rugose seabed morphology and hard shallow authigenic carbonate bodies (Figure 1), gas wipeout zones and the presence of thick wedge of bright amplitude events. Figure 2 illustrates the Poor Data Zone (PDZ) over the center of the field, characterized by weaker amplitude and lower dominant frequencies. This zone extends up to the seabed. Amplitude brightening near the seabed overlying the PDZ indicates the presence of materials that generate high-impedance contrasts. Core samples taken showed they are authigenic carbonate that forms a hard crust and acts as scatterers of seismic energy. Presence of gas below the authigenic carbonates further weakens the seismic energy through absorption. The presence of the thick wedge (Figure 2) has a similar effect to the underlying events. In general, the seismic data over the structurally complex M Field is highly variable.
Innovative Risk Management on the Barzan Onshore Project
Authors: DeHart Bob , Brand Johnny 
Published: March 2015

Abstract
The Barzan Gas Project is being developed by Barzan Gas Company Limited, a joint venture between Qatar Petroleum and ExxonMobil Barzan Limited, with RasGas Company Limited as the developer and operator. The project's objective is the economic development of a high quality, reliable and fully integrated sales gas facility that further monetizes Qatar's North Field resources to supply gas to the domestic market for power generation and water desalination.
JGC was awarded the Engineering, Procurement, and Construction (EPC) contract for the Barzan Onshore Project on January 1, 2011 for design, procurement, and construction of two of the largest natural gas processing trains in the world. The workforce on site has peaked with 29,500 workers from 45 countries representing 20+ languages.
The project has displayed world-class Safety, Health, Environment and Security (SHE&S) performance due in part to its SHE&S Management System. For the EPC phase, the current Lost Time Incident Rate (LTIR) is 0.006 and Total Recordable Incident Rate (TRIR) is 0.169 based on 195 million man-hours worked as of October 1, 2014. Only six (6) Lost Time Incidents (LTI) have occurred project to date. Between July 11, 2012 and March 25, 2014, the project attained 130 million man-hours without an LTI.
The paper provides an overview of four (4) areas that have significantly contributed to the success of the project. The areas include emergency response and coordination; medical management; man-machine interface and heat stress management. Although the areas are standard in most projects of this scale, the organisation, effectiveness and level of implementation are very unique, with pioneering work being done in certain elements within these areas.
Exploring Channel Reservoirs in a Frontier Area Using Regional 3D CSEM and 2D Seismic
Authors: Pedersen Haakon Toralv , Hiner Mike 
Published: March 2015

Summary
In this paper we explore the West Africa-South America analogue proven by the Jubilee and Zaedyus discoveries in Ghana and French Guiana, respectively. Instead of the Turonian turbidite fan reservoirs, we consider younger unproven deep water channel systems in Foz do Amazonas Basin in Brazil which could be analogous to the Campanian pay found in the Teak field in Ghana. We present a geological overview of the basin together with acquisition details and imaging results of a regional 3D CSEM survey in the area. Using CSEM as a fluid indicator, we calculate the Net Rock Volume (NRV) from a channel-shaped EM anomaly and with conservative parameterization we obtain a P10/P90 ratio of 14.7 and an average NRV of ~23000hm3.

Introduction
In September 2011 Tullow Oil announced a significant oil discovery in the Zaedyus prospect in French Guiana that established the Turonian aged Jubilee play from Ghana, West Africa. Following the Zaedyus discovery, a 2012–2013 drilling program of 4 exploration wells targeting nearby turbidites resulted in disappointing commercial success. We will discuss the potential of the younger channel play in the lower Tertiary and upper Cretaceous in Foz do Amazonas basin rather than the Turonian turbidite fans. Continuing the West Africa/South America analogue, the channel systems could resemble the Campanian pay of the Teak-1 exploration well in Ghana (Kosmos Energy, 2011). First, we will give an overview of the geology providing potential reservoir and trapping mechanisms. Second, we will use results of a regional multi-client 3D CSEM survey as a fluid indicator. Acquired in 2013, the survey is bordering French Guiana towards west within 15km of the last exploration well of the drilling program, GM-ES-5, and within 50km of the Zaedyus discovery. Third, we will use the method introduced by Baltar and Roth (2013) to estimate the Net Rock Volume in a sub-region of the CSEM coverage.

Geological overview
The present day shelf margin region of the Foz do Amazonas Basin has undergone significant modification from mass wasting events and debris flows. The basin provides analogous examples for deep water depositional systems in the underlying Tertiary and Cretaceous sections. Based on seismic observations, the shelf is shaped by the orientation of shallow basement that is interpreted as continental crust from potential field data. The basement extends outward from the coastline for approximately 130 kilometers before rapidly dropping off in a series of complex fault systems that are related to older rift stage graben systems.
Radiation Protection Management in Design Activities
Authors: Cerri Paolo , Di Giacinto Luigi , Fantoni Roberto Fresca 
Published: March 2015

Abstract
Eni has recently started up a plant for conversion of heavy crudes and residues into light products based on the propritary "eni slurry technologies"
Extreme conditions of fluids (high pressures and temperatures) have required the adoption of contactless process equipment transducers for measurements of levels and density of fluids inside vessels and reactors (figure 1). These transducers are mainly based on the determination of the attenuation of gamma radiation beams generated by a radiation source.
More than 90 of such devices have been required.
When a radiation protection system is developed after the construction of plants, this may lead to costly and burdensome interventions. For instance, in case of too high radiation dose rates in areas close to radioactive sources, additional shields can be installed or it may be required the delimitation of some areas of the plant making it inaccessible.
In this project a radiation protection management system has been developed as part of the engineering design: International Commission on Radiological Protection standards have been taken into consideration. starting from the purchasing requirements definition and 3D model analysis (figure 2)., the International Commission on Radiological Protection standards have been taken into consideration.
Three Dimensional Visualisation of Solvent Chamber Growth in Solvent Injection Processes: An Experimental Approach
Authors: Fang Fang , Babadagli Tayfun 
Published: March 2015

Solvent based methods have been recommended as an alternative to thermal techniques for heavy oil and bitumen recovery. However, the cost of solvent injection processes is high and therefore requires a careful design of field scale applications. Yet, the efforts have been limited to numerical or analytical models in clarifying the complex physics of solvent processes due to difficulties in experimentation.
Vapor extraction (VAPEX) is one of the solvent applications suggested and tested for heavy-oil/bitumen recovery from unconsolidated oilsands. In this method, solvents are injected into the reservoir through a horizontal well and gravity drainage takes place resulting in the production from the lower production well. Theoretical analyses suggest that a solvent chamber develops and the displacement is controlled by its growth during this process. Previous studies, however, showed the possibility of unusual behavior at the reservoir scale reservoirs such as stopping, shrinking, and even disappearing of chambers associated with severe fingering phenomena. These kinds of anomalies can only be identified through experimental designs and, so far, have been limited to 2-D models with minimal visual support.
In this paper, a three dimensional imaging technique using laser is introduced. Refractive index matching of solvent, oil, and glass beads pack enabled imaging the progress of solvent displacement. 2-D images of slices with little spacing in the scaled VAPEX model were recorded within a significantly short time using laser sheets. Then, 3-D images were generated by integrating the 2-D images.
In simulating the VAPEX model, different injection rates were applied and different sizes of glass beads were used to create different permeability media to also study the physics of the process parametrically. 3-D images were analyzed to understand the chamber growth process during VAPEX. The observations are expected to be useful in clarifying many uncertainties of the VAPEX process and also provide data for further computational studies.
A Safe and Efficient Method of Surface Interception to Access Outermost Sealed Annulus Charged with Abnormal Gas Pressure - Relieves Well Integrity Concerns
Authors: Das Prashun Kumar , El-Mandrawy Wael Moneer 
Published: March 2015

Abstract
One of Qatargas' newly acquired ventures, is located in the North Field offshore Qatar. The wells are typically 7 inch monobore completed with a 26 inch conductor and three casing strings. Conductor is driven to a pre-determined depth and the surface casing is set to a depth which was later found to be in proximity to a shallow gas formation. Primary well design did not include any provision to monitor and control the annular parameters between the surface casing and the conductor (D annulus).
Abnormal rise in C & D annulus pressures during the last phase of drilling highlighted the need to investigate the condition of the producing wells on other platforms. Chances of inner annuli getting charged with shallow gas pressure and possible communication to D annulus was thought to be a well integrity concern. Lack of access to a sealed D annulus did not allow evaluating its status. Establishing a safe access to a sealed and potentially gas charged containment (D-annulus), thus, posed an engineering and operational challenge.
First section of this paper looks at the probable reasons of intrusion of hydrocarbon gas in the annuli and analyses the associated risks. It also deliberates the challenges to find a safe and innovative method of establishing an access into the sealed containment (D annulus) and installing an outlet equipment to control and monitor annulus pressures. It speaks about a detailed risk analysis, a factory stack up test carried out to test a tailor made hot tapping arrangement.
Second section elaborates installation of a real time monitoring and bleed-off arrangement on the D annulus, enabling a safe and a convenient way to manage the annulus pressures and the lessons learnt during implementing the interception process.

Introduction
Qatargas North Field is located offshore, northeast of Qatar in the Arabian Gulf and is the world's largest non-associated gas field. The sour, slightly over-pressured natural gas is contained in the Khuff carbonate formation. In one of Qatargas' newly acquired ventures, wells are drilled and completed on 3 unmanned offshore platforms (#1, #2, #3). Wet gas from Khuff formation is produced from these wells and is sent to onshore processing facility through two sub-sea pipelines.
The wells are typically 7-inch monobore completed with a 26-inch conductor and three casing strings. A 7-inch liner is set across the Sudair and the Khuff reservoir. Wells are completed with a liner top isolation packer, tied back to surface with 7 inch CRA tubing. This general design has been used by all other operators in the North Field and is field proven. Figure 1 shows the general completion design of the wells.
The annuli between the well casings are numbered as A (7-inch x 10 ¾-inch), B (10 ¾ inch x 13 3/8 inch), C (13 3/8 inch x 18 5/8 inch) and D (18 5/8-inch x 26-inch). Provision was available for monitoring and bleeding off pressures in A, B and C annuli.
A Non-Isothermal Wellbore Model with Complex Structure and Its Application in Well Testing
Authors: Zheng Shi-yi , Zhang Yiqun 
Published: March 2015

Abstract
During oil field development, with the installation of Permanent Downhole Gauge (PDG) and Distributed Temperature Sensor (DTS), large volume of high resolution, real-time and continuous monitoring of downhole temperature, pressure and sometimes flow-rate are available. The dynamic temperature data have been interpreted in practice, where it has been confirmed to provide characteristic information of the reservoir.
Although the wellbore is in a non-isothermal environment, heat transfer between the fluid in wellbore and the formation is often ignored and temperature is usually assumed constant in the data interpretation which will lead to misunderstanding of the pressure profile. Another problem comes from the pressure transient analysis which cannot get monolayer production exactly in dual-layer and multi-layer testing. Alternatively, changes of temperature in the wellbore can be used to calculate production and evaluate reservoir thermodynamic properties.
In this work, firstly, wavelet transform as well as a non-linear regression analysis method were utilized to study the relationships within down-hole temperature, pressure and flow-rate. Then, a non-isothermal wellbore model that is capable of predicting the temperature, pressure, flow-rate and liquid fraction profiles under multi-rate and multiphase production scenarios was established, this numerical wellbore model calculated temperature and pressure separately and iterated until the estimated and calculated values converge. After that, this model was compared with another published two heat transfer models to verify its reliability. Finally, the wellbore model was coupled with a reservoir model to reproduce the transient temperature behaviour at location of gauges.
This paper provides a way to not only integrate pressure data, determine the flow-rate profile more accurately, but also estimate typical thermodynamic parameters such as porosity, permeability, viscosity, and Joule-Thomson coefficient of the fluids by matching the simulated results with the real transient temperature data measured by PDGs. In addition, the trainsient temperature data may also be used as a fast and reliable diagnostic tool in well testing analysis to detect the end of wellbore storage.
Quantification of Uncertainty of Reserves with High Quality History Matching Models in a Mature Field
Authors: Tewari Raj Deo , Jeong Daein , Khalid Ruzanna Mohd , Kittrell Chuck , Tengku Othman Tengku Rasidi 
Published: March 2015

Abstract
Development decisions of oil and gas fields are based with many uncertainties within the supporting data. Uncertainties are larger in the beginning which gets reduced with time as more data is acquired and understanding of the field is improved. However, significant uncertainties persist even in mature fields which are case for redevelopment. Therefore, enormous inherent uncertainties need to be characterized, analyzed and incorporated in the simulation study to the extent possible in order to improve the decision making process.
This paper discusses the relevance of reviewing and incorporating the field uncertainties related to geological and/or dynamic properties in estimation of incremental volumes in the redevelopment of a mature oilfield. Reservoir models need to be updated through history matching process to reflect actual measurements from reservoir. In this study a workflow to quantify the uncertainty of a mature oilfield of offshore Malaysia and to estimate the incremental oil potential from infill wells has been designed. During history matching process, dynamic and static parameters of uncertainty, relative permeability curve, local permeability around wells, the aquifers? volume and productivity, and contacts between gas-oil, and oil-water have been considered. An objective function is applied for the history matching which consists of the error between simulated and observed data from wells. An "Evolutionary strategy optimization", proprietary to MEPO software is used to obtain multiple equivalent models with high quality.
While running an optimization for history matching, the ranges of uncertainty parameters have been narrowed and adjusted the ranges to be used for quantification of uncertainty of Estimated Ultimate Recovery (EUR). In the prediction stage, both filtered models from actual runs and sampled models from Latin Hypercube have been used. This approach not only allows to evaluate intrinsic uncertainty, but also to keep the variety and risk of prediction. Monte-Carlo simulation technique then makes it possible to acquire the distribution of EUR.
Mass Transport Deposits (MTD) in Deepwater Sediment System Can Be Used in Delineation Deepwater Reservoir Presence
Authors: Nur Syuhada Raja , Ahmad Nasaruddin 
Published: March 2015

Introduction
In Malaysia, three known classic deepwater sediments have been identified. The sediments are located on Peninsular Malaysia and Sabah respectively. There are (a) Triassic Semantan and Semanggol Formation in central and western part of Peninsular Malaysia, (b) Oligocene West Crocker Formation outcropping in the onshore NW Sabah and, (c) Miocene to Pliocene Fan System in offshore NW Borneo. These deepwater sediments have been studied in detail by oil and gas industry. The stratigraphic chart for these deepwater sediments are summarized in Figure 1.
This paper discusses the recent observations from offshore exploration in Sabah and the insights gained from utilizing the outcrops as analogues to the NW Borneo Fan System especially Mass Transport Deposits (MTD). This paper focuses on integrating the outcrop studies, seismic interpretation with calibration of well logs and image data for deliberating the deepwater systems in offshore Sabah. Discussion on the High Density Turbidite System (HDTS) and Low Density Turbidite System (LDTS) also captured to understand the controlling factor of deepwater sediment distribution. The location of the key outcrops as reported by various authors and the offshore study area for this paper is shown in Figure 2.