bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advances in Wet Gas Pipeline Technology
Authors: Pacheco Jorge Luis , Sisak William J. , Venaik Sunil , Reddy Ramani V. , Robson David R. , Dhokte Atul , Wright Eric John , Pugh Dylan , Curtis Christopher E. , Hickman Scott Ralston 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
Subsea pipeline transportation of wet gas over significant distances to an onshore or offshore facility for processing can be a key element in the development of large offshore gas resources. Full well stream carbon steel pipelines offer substantial cost advantages over alternatives such as offshore gas dehydration or pipelines clad with corrosion-resistant alloys. However, such well streams are typically highly corrosive to carbon steel and subject to complex and variable multiphase flow conditions. Realizing the twin objectives of optimum capital expenditure and long-term facility integrity, therefore, requires both a comprehensive flow assurance approach and a robust, highly effective corrosion control program.
This design approach requires close integration of flow assurance and corrosion technologies. Specifically, accurate flow modeling is used to predict the nature of the produced fluids in contact with the pipe wall as a function of the location in the pipe. Corrosion inhibitor qualification testing is then conducted in fluids that simulate the range of anticipated service conditions in terms of both chemistry and hydrodynamics. This paper describes the application of enhanced flow modeling and corrosion testing to more accurately simulate the local top of the line environment for large diameter, sour wet gas lines and to define a comprehensive inhibitor qualification plan and corrosion management program. Operational, facility design and technology lessons learned in implementing these advances in a major project are presented.
3-D Seismic Attributes Applied to Carbonates To Detect Small Faults and Potential Fractures: A Case Study From Kuwait
Authors: Syed Ismail Mohammed , Al-Ajmi Bader 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
In general it is difficult to map minor faults and other trace to trace discontinuities hidden in 3D seismic data which has direct bearing on proper reservoir description. Often these subtle faults and discontinuities appear as minor changes in seismic waveform which are not easily correlatable to map them by conventional interpretation techniques. To map these appropriate 3D seismic attributes sensitive to the existence of subtle faults and fractures has been investigated in the target reservoir, the Early Cretaceous (Albian) Mauddud Formation of Raudhatain Field of North Kuwait. Raudhatain field is one of the major fields of North Kuwait. It is a faulted anticlinal dome having two sets of faults and produces from reservoirs in Zubair, Burgan and Mauddud formations. Our main objective of the study was to gain better understanding of and to predict the possible fractures in Mauddud reservoir to improve the structural frame work for effective future planning of development and injector wells based on the findings. Major faults are easily identified at top and base of Mauddud due to large acoustic impedance contrast between Mauddud and clastic units of Wara and Burgan above and below. Smaller faults and possible fractures within Mauddud are difficult to map due to lack of vertical resolution and poor S/N ratio within the reservoir interval. To overcome this various 3D seismic attributes were computed and investigated. Horizon and volume based attributes (Dip & Azimuth, Curvature, Shaded relief, Spectral decomposition and coherency) were used integrating with sub-surface data to arrive at the best possible structural frame-work of the reservoir.
IOR/EOR in South Oman Heavy Oil Fields
Authors: Sikaiti Salim , Regtien Jeroen M.M. , Azkawi Ahmed A.S. , Al Harthi Said , Leith Elaine Sandison 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
Several heavy oil fields in Oman are undergoing a rejuvenation using a variety of Improved and Enhanced Oil Recovery methods. The sandstone reservoirs, generally at a depth around 1000 meters, contain heavy oils with API gravities of 18–22, viscosities between 90- 400 cp and exhibit variable reservoir properties of around 20% porosity and 500–2000 mD permeability. Mobility ratios are adverse and all fields demonstrate early water breakthrough and high BSW under primary development. Fields with strong bottom waterdrive are redeveloped with a focus on cost effective infill drilling and water shutoff techniques. Good results have been achieved through segmentation of horizontal well bores with swellable elastomers allowing for targeted mechanical or chemical water shutoff. Innovative infill drilling technologies such as jet drilling and ultrashort radius are either ongoing or in preparation. Further increases in ultimate recovery through in-situ-combustion and high-pressure steam injection are being pursued. The fields with weak or no aquifer support are being redeveloped through waterfloods and chemical or thermal floods. Execution of a polymer project is ongoing with first polymer injection expected in 2008, following a very favourable waterflood response despite geological complexities and adverse mobility ratios. Studies are ongoing into expansion to other areas and a follow-up alkaline surfactant polymer flood. The redevelopment rationalized the existing infrastructure and provides support for waterfloods in satellite fields as well. Redevelopment of a second group of fields is being pursued through thermal methods. Steam injection tests are in final stages of preparation and will start in 2007, followed by phased full field developments. Given the specific reservoir and fluid conditions there are not always analogs and several of the developments pose unique challenges. The paper will present a status overview of several waterflood, polymer and thermal projects as well as key challenges and solutions.
Wamsutter's Integrated Seismic Program-Transforming Land Seismic, From Data Acquisition Through Interpretation and Analysis
Authors: Ramkhelawan Rosemarie T. , Hicks William Alan , Bruce Colin T. , Cooper Craig W. , Hornby Brian , Hornbeck James A. , Wardhana Ricko 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
The US Onshore Wamsutter Field Development Team executed two seismic field trials in 2006: a borehole seismic field trial and a cableless surface seismic field trial. The borehole seismic field trial consists of a 4-well crosswell tomography program, and acquisition of a massive 3D VSP with 8000 ft of 3C receiver tool deployed in the wellbore and 6000 surface vibroseis source points. The surface seismic field trial is the world's first deployment of the FireFly cableless seismic acquisition system, with 8300 3C digital sensors deployed, and 7200 explosive source points. These field trials were designed to increase seismic resolution, improve imaging and identification of higher porosity zones, and increase fault and fracture detection, with the ultimate goal of optimizing field performance. The data that was previously available for interpretation had a dominant frequency of 25 Hz, which allowed us to image reservoir thicknesses of greater than 50 feet. The producing reservoirs have much lower average thicknesses, which have been targeted with the new higher resolution crosswell, 3D VSP and dense surface seismic data. Rock properties understanding of the Wamsutter reservoirs has been fundamental to well-to-seismic calibration and interpretation and analysis of the seismic datasets. Seismic forward modelling has been undertaken to calibrate the seismic responses, as part of a larger integrated effort to understand porosity and lithology responses and fracture anisotropy. Field acquisition presented many challenges which were safely and successfully overcome. The crosswell data has resolved reservoir thicknesses of less than 20 feet. Frequencies from the 3D VSP are better than historically recovered in surface seismic data. This integrated borehole/surface seismic approach has allowed us to better understand the seismic responses and calibrate rock properties to different levels of seismic resolution. The Wamsutter Seismic Field Trials is a true success story worth sharing globally.
Do Fluid Compositions and Reservoir Pressure Tell Us the Same Thing About Reservoir Segmentation?
Authors: Gong Changrui , Bunney John R. , Osborne Mark , Zhou Joe , Caruthers Dan , Barwise Tony , Chen Zhangxin 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
A multitude of reservoir fluid parameters (pressure, GOR, molecular composition, etc.) are usually available for reservoir segmentation interpretations. These parameters are controlled by multiple reservoir processes including, but not limited to, reservoir charge/filling, fluid mixing through darcy flow/advection/diffusion, gravity segregation, biodegradation, fractionation, and differential leakage. The time scales for these processes to operate in reservoirs will be the key to understanding the relative significance of fluid data to reservoir compartmentalization studies. Numerical simulation provides us a platform to put these reservoir processes to test. Validation and prototyping of the miscible fluid mixing simulation have generated results consistent with analytical solutions and other numerical simulations (Smalley et al., 2004). Preliminary results from simulation for simple geometrical reservoir models suggest that pressure equilibration is the fastest and is several orders of magnitude shorter in time scale than density/composition through convection or through diffusion processes. Thus same pressure gradients do not necessarily mean that fluids have equilibrated in composition in reservoir compartments. We may need to attach different degrees of significance to pressure and fluid compositional data in reservoir segmentation assessment. Field case studies will be presented to apply the fluid mixing simulations to explain fluid data distribution and composition variations. This study will reduce the uncertainties associated with reservoir compartmentalization interpretation using fluid property data and help to optimize oil field development and production.

REFERENCES
Smalley, C., England, W.A., Muggeridge, A., Abacioglu, Y. and Cawley, S. (2004) Rates of reservoir fluid mixing: Implication for interpretation of fluid data. In: Cubitt, J.M., England, W.A., Larter, S. (Eds.), Understanding Petroleum Reservoirs: towards an Integrated Reservoir Engineering and Geochemical Approach. Geological Society, London, Special Publications, 237, 99–113.
Development of highly contaminated gas & oil fields, breakthrough CO2/H2S Separation Technologies
Authors: Klaver Theo C. 
Published: February 2016

Abstract

Description
Shell Global Solutions International B.V ("Shell") has been involved for many years in the development of new technologies to separate CO2 and H2S from highly contaminated natural gas streams. This program has been significantly accelerated in recent years and major milestones have been achieved. The program focuses on technology solutions that are critical to develop (stranded) contaminated hydrocarbon gas and oil fields.
Several key technical challenges in the development of highly contaminated gas & oil fields have been overcome with new technologies developed by Shell. These challenges include: contaminant separation at minimal energy consumption and losses at minimum capital investment.
This paper will present these challenges and introduce new technologies that can help to reduce project development cost by as much as 40% compared to conventional technologies

Application
External studies (Steiner, 2005) estimate a global (recoverable) resource of some 500 B boe (= 3000 tcf), as per bar chart figure 3 below, of gas that is 'contaminated' by the previously defined levels H2S and/or CO2. These resources will require specific technologies to develop these fields economically. The bulk of these resources are in the Middle East, Canada, CIS, Asia and Australia. In general, one could say that the predominantly H2S contaminated fields can be found in the northern Americas (Canada), the Middle East (Abu Dhabi, Kuwait, Oman, Saudi Arabia, Qatar), and the Caspian regions (Kazakhstan, Russia). The indicated size exclude resources that could be accessed via H2S / CO2 Enhanced Oil Recovery (EOR).
The application of the newly developed technologies will be in the area of contaminated gas fields. With new technologies highly, contaminated gas fields can be economically developed to remove the contaminants from the hydrocarbon gas and re-injection of the contaminants. Since conventional technologies become less economic at increasing percentages of contaminant, the new technologies are specifically targeted at high concentrations of contaminants (&gt;30%). The new technologies aim for efficiencies above 85 %, where efficiency is expressed as a percentage of hydrocarbon sales gas divided by the hydrocarbon feed stream. (Losses are due to fuel gas and hydrocarbons left in the contaminant stream)
A New Method In Well Test Interpretation Using Temperature Transient Analysis For Gas Wells
Authors: Bahrami Hassan , Siavoshi Jamal 
Published: February 2016

Abstract
Interpretation of temperature logs has been done successfully in wells to identify water or gas entries location, detect casing leaks, and evaluate cement placement. This paper shows how knowledge of the Joule-Thomson cooling effect and frictional heating effect can be applied for well test interpretation.
Many analysts rely on pressure derivative curve to diagnose wellbore storage period and radial flow regime on pressure transient data. However, there are field examples that flow regimes can't be accurately determined.
During transient tests, both pressure and temperature are changed depending on downhole flow rate. In gas producing wells, Joule-Thomson cooling and frictional heating effects are the main dynamic factors causing flowing bottomhole temperature to differ from the static formation temperature at that depth. When a gas well is shut in, JT cooling effect is vanished and this causes a sharp increase in sandface temperature. As effect of WBS ends, wellbore temperature gradually cools down due to heat conduction with near wellbore region.
This paper demonstrates a new technique for determining end of wellbore storage in pressure build-up tests for gas producing wells using temperature transient data. Application of this robust technique was demonstrated using three gas wells in which both temperature and pressure transient data were analyzed for more accurate welltest interpretation.

Introduction
In pressure transient tests [1], the early portion of the well test data is usually affected by the wellbore storage effect and might be influenced by skin[2] and reservoir permeability.
The wellbore storage effect delays the formation pressure response and distorts the early portion of pressure transient data. Diagnosing of the radial-flow regime is crucial to quantitative interpretation since it provides values for permeability and skin. Unit slope and the plateau on the pressure derivative curve as well as Horner plot are usually used to identify pure wellbore storage and radial flow regime as shown in Fig.1. The interpreter's first task always is to identify the unit slope line and derivative plateau to identify flow regimes [3].
Multi-Disciplinary Reservoir Description to Characterize Connectivity in a Complex Minibasin Fill: an Integrated Approach at Holstein Field
Authors: Wiseman Terrence Robert , Ballin Paulo Roberto , Lederer Mark C. , Wagerle Roger N. , McCaslin Neal F. 
Published: February 2016

Abstract
Holstein is a BP operated, deepwater oil field located in the Gulf of Mexico. Reservoirs comprise stacked, Pliocene turbidite sands with the field formed by a large, steep, southeasterly dipping, monoclinal structure.
Early performance of the field showed a sharper production decline than predicted by the sanction study. Dynamic simulation of early wells suggested limited drainage acreage confined by baffle regions with limited connection to the larger reservoir. A campaign of surveillance data was carried out. Subsequent drilling indicated the reservoirs, originally modeled in pressure isolation, were experiencing pressure depletion through connections between reservoirs. A major effort was undertaken to recharacterize the reservoir, rebuild the static model and generate new dynamic simulations in order to update the development strategy and develop a mitigation plan.
The sanction case geological model described the reservoir sands as being deposited in a ponded, intraslope, salt basin dominated by thick, amalgamated reservoirs with internal homogeneity and excellent connectivity. The subsequent recharacterization describes reservoir architecture elements composed of sandy sheets and channels that shingle to form genetically related reservoirs. Baffling between geobodies and pressure isolated compartments between some shingles are also recognized. Post-depositional modification of the reservoir further complicates well performance by removing reservoir entirely or reducing thickness. A structural overprint creates deformation bands which appear to reduce well productivity through reduction of effective permeability in the structurally steepest segment of the field. In addition, seismically resolvable faults, originally thought to be sealing, are modeled as having variable transmissibility and allowing cross-flow between the complex reservoirs.
A revised heterogeneity model calibrated with dynamic data allowed greater understanding of well performance variations. The assisted history match approach TDRM(4) was utilized to handle the main uncertainties in the field and reach multiple models with good match to all production and pressure data available. These cases used on prediction allowed analysis of production strategies for optimizing recovery.
The data that guided this model rebuild, the integrated modeling process used and the resulting impacts on the depletion plan are described in this work.

Introduction
Holstein is a BP operated, supra-salt, deepwater oil field development discovered in early 1999 in the northern Gulf of Mexico. The field sits under approximately 4300 ft of water 150 miles south of New Orleans and primarily comprises blocks 644 & 645 within the Green Canyon offshore continental shelf protraction area (figure 1).
HPHT, Low Permeability Fields in South Texas...A Legacy of Development in a Tough Environment
Authors: Sodersten Sandra Sue , Sihi Debasish , Cisar Marilyn Taggi 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
For over fifty years South Texas has been a part of Shell's producing portfolio. These fields present a wide spectrum of technical, operational, and regulatory challenges. Current fields are a mixture of legacy properties that Shell has operated since the1950's, small but lucrative new discoveries proximal to existing production, and fields acquired in an asset swap with Total in 2006. Well locations range from rural ranchlands to in- town locations near a major airport. Production is almost exclusively gas and associated condensate from Tertiary aged sandstones in the Wilcox, Vicksburg and Frio formations. Reservoirs are generally high temperature and highly geo-pressured. Most of the reservoirs are considered tight gas sands, with porosities ranging from 9–20% and permeabilities in the 0.01 to 1 md range. Wells generally range from 9000 to 16,000 feet with an occasional well targeting a deeper objective. A five-rig drilling program, drilling 30–35 wells per year, maintains production in these 40+ year old fields. Targets for development include infill drilling, field extensions, and deeper objectives in existing fields. Constant vigilance on cost and innovations in drilling and casing design have been employed to maintain profitability of these projects. Integration of all technical specialties from the geosciences to facilities has been critical to making these difficult operations run successfully. This paper will overview some of the technical and business challenges that we have to meet to continually regenerate profitable development opportunities. Many of the traditional tools and techniques of sub-surface analyses do not work very well in this environment. We will discuss some of the tools and techniques that we have found to be useful. We also plan to discuss how we have established ourselves as the best-in-class in south Texas Operations giving us a competitive advantage.
Seismic monitoring feasibility on Bu-Hasa field
Authors: Marvillet Christophe , Al-Mehairi Yousuf Saadalla , Shuaib Mohamed , Al-Shaikh Ahmed , Desegaulx Pascal , Hubans Christian , Thore Pierre 
Published: February 2016

Abstract

Summary
A 4D seismic feasibility study has been performed on carbonate reservoirs of the Bu Hasa field onshore Abu Dhabi. It concludes to the feasibility of the method as a reservoir injection monitoring tool, an interesting result when several recent papers [1] have suggested that 4D seismic may not be applicable to Middle East carbonate reservoirs due to their rock physics characteristics.
2D full wave equation and 3D convolutional modelling approaches have been combined in this study in order to maximize the reliability of the predictions while optimizing the cost effectiveness of the study.
Because the assessment of repeatability noise indicated a realistically irreducible threshold for high resolution 4D surface seismic and a possible limitation for WAG monitoring, a 4D well seismic exercise was simulated which overcame those limitations.

Introduction
The Bu Hasa Field, onshore Abu Dhabi, is a super giant carbonate oil field. The Lower Cretaceous Shu'aiba member of the Thamama formation is the main reservoir with porosity above 30%. This field has been producing since 1963 and production mechanism is involving peripheral water injection and crestal gas and water injection. (Figure 1)
The "monitoring" of this field is essential to optimize the production parameters and the value of using seismic information (4D) as an additional reservoir monitoring tool has been assessed [2]. Although seismic is not always considered as fit for purpose for limestone reservoir monitoring because of the stiffness of the rocks, Bu Hasa field is a favourable case because of the high porosities encountered. (up to 30%) Bu-Hasa oil is light and very compressive; therefore, the mechanical behaviour of the oil is closer to gas than water. This means injected water front movements should be more easily detected than injected gas front (in the oil).