bluuebunny/crossref_metadata_2025_split huggingface dataset:
Workflow for Asphaltene Precipitation Assessment and Mitigation Strategies
Authors: Zhou Honggang , Passade-Boupat Nicolas , Gonzalez Marianna Rondon 
Published: November 2012

Abstract
The prediction of the risk of asphaltene precipitation is an important topic in the petroleum industry. It usually requires representative samples and measurements using specialized, high-pressure equipment, and may have to be performed on many different fluids from various reservoirs. Of the many fast screening methods have been proposed, most of them only take into account the hydrocarbon phase without any investigation on the actual asphaltenes in the crude, and may lead to erroneous predictions.
This paper presents a universal approach of the risk of precipitation of asphaltenes.
A new experimental way to perform fast screening of asphaltene instability is proposed based on relevant solubility properties of the asphaltene fractions. It is based on two major parameters: the live oil solvent properties (based on PVT analyses) and the actual solubility of asphaltene fraction, through an easy characterization procedure that examines the solubility of asphaltenes in heptane/toluene mixtures. In field development projects, this method, which can be performed on dead oil samples, helps limit the investigation to fluids that present a real risk of asphaltene precipitation.
If a precipitation risk is stated, two paths are followed in order to estimate the risk level, and to prepare a mitigation strategy. Additional tests, performed on pressurized representative samples or taking into account reorganization of asphaltenes from different fluids, will help to define the severity of the risk. For mitigation, an advanced test set-up has been developed, which facilitates evaluation of the efficiency of chemical additives to prevent plugging under flow conditions of fluids above the asphaltene precipitation threshold. Depending on the crude oil, the severity of the precipitation conditions, and the nature of the additive, the blocking of a capillary tube can be delayed or prevented.
A Break Through In Monobore Completion System by Using New Design "One Run" Upper Completion System
Authors: Ghayoomi T. , Hashemi M. H. , Karami P. , Javadian M. , Ueland G. , Ibragimov A. , Delavar A. 
Published: November 2012

Abstract
Majority of the high rate gas wells in the world are completed with Monobore completion system. The conventional sequences of running Monobore completion in giant gas field of SouthPars are in three steps: Run No. 1 which includes running Liner and liner hanger by drill pipes (DP) and normally followed by cementing behind liner, Run No. 2 which includes Running Tie Back production Packer with 15 ft Polished Bore Receptacle (PBR)by setting tool and DP and finally Run No. 3 which includes running completion string with upper seal stem and at the end complete the well with proper space out. Running of tie back production packer with setting tool and DP in one step and running upper seal stem by tubing in last step has some concerns (More Rig time, cost, safety, etc).
Feasibility Study and research was carried out to check the possibility of combining the run No. 2 and 3 together.
A new method has been developed and after successful surface test it was run in one of gas wells in South Pars giant gas field in Persian Gulf. All pressure tests after installation were satisfactory. This procedure saved almost 1.5 day of rig time and protected seals against mechanical damage while running in the hole.
Martin Linge Electric Power from Shore
Authors: THIBAUT Edouard , LEFORGEAIS Bruno 
Published: November 2012

Abstract
Martin Linge offshore gas field (formerly named Hild) is located on the Norwegian sector of the North Sea, southwest from Oseberg. The field development comprises a platform with a jack up rig and Floating Storage Offloading unit. This offshore development will be supplied with electric power from shore, through a High Voltage AC submarine cable.
With a step out distance of 170km and a design power of 55MW, this will be the world's longest AC submarine cable power supplying an entire offshore Oil and Gas platform from the shore.
This paper presents the Martin Linge project, it discusses the criteria considered to select a power from shore instead of an offshore Gas Turbine power plant which is the current practice in the offshore Oil and Gas industry.
And since in a first approach, for such long step-out distance, the choice of power from shore would be to select a DC transmission line, the paper discusses the design, system approach and main technical challenges of this long step-out AC transmission development.
Finally, the paper gives an operator's viewpoint as to the way forward.
Pushing-up Field Ultimate Recovery to Top Quartile through Infill Development - A Case Study of a Carbonate Waterflood Field
Authors: Garimella Sai , Kharusi Ahmed , Wahaibi Hamed , Goossens Peter , Warrlich Georg , Kindy Zaher , Harris Jeremy , Al Lamki Ali 
Published: November 2012

Abstract
PDO has a diverse portfolio of mature fields undergoing waterflood. These fields open-up an additional opportunity through infill drilling for enhancing the ultimate oil recovery. It has been established in the oil industry that increased well density does not only result in acceleration but will also lead to incremental recovery. This paper demonstrates the approach taken for identifying and maturing an infill development in a Shuaiba matrix carbonate reservoir within a thin oil column. The case study field has been developed predominantly with single long (~ 1.5 km) horizontal oil producers (lifted with ESPs) & water injectors in a Producer-Producer-Injector (PPI) pattern with a ~60 m spacing between Producer and Injector (P-I).
The development team executed additional appraisal activities in parallel with implementing the field development plan. Seismic inversion was updated with the new well results which improved porosity prediction in un-drilled areas. Based on acoustic impedance guidance, appraisal wells have been drilled with encouraging indications in terms of producibility and opened new areas for further development. The history matched simulation model results showed that 120 m P-P-I spacing would recover 25% of in place volumes compared to 60 m P-P-I spacing with an ultimate recovery factor (URF) of 45%.
The key success factors for the infill development are (1) well placement with geosteering, (2) balancing appraisal with development and (3) continually updating static and dynamic models. This is done to support development decisions such as well sequencing & placement, drilling activity and surface facilities expansion. The key learning from this case study is that developing fields initially with twice the proposed development spacing, nevertheless following the optimal water flood pattern, is the best way for appraising the whole field rapidly. This allows time to gather much needed information ahead of making tactical investment decisions on long lead-time surface facilities.
The case study field development & maturation activities enabled pushing-up the ultimate recovery above 33%, bettering the top quartile recovery factor and achieving a sustained oil production forecast of above 20,000 units for the forthcoming 6+ years. The methodology developed and presented in this paper could be adopted for typical water flood developments.
Leak Detection by Temperature and Noise Logging
Authors: Mohamed Ihab Nabil , El-Hamawi Mohamed , Al Hassan Rasheed Ahmad , Aslanyan Arthur , Filenev Maxim , Aslanyan Irina , Bargouthi Jamal , Salim Bassam 
Published: November 2012

Abstract
Monitoring and handling Sustainable Annulus Pressure (SAP) is a daily challenge in today's oil and gas industry. Well integrity failure can affect production and the environment and, consequently, lead to high economic losses from fixing the resulting damage. Once SAP is confirmed, its source should be located and shut off as soon as possible. The biggest problem is leaks behind multiple barriers, which are not clearly seen in conventional temperature and noise logs.[1] However, recent developments in temperature and noise logging tools and interpretive techniques have been rewarded by achieving high resolution and sensitivity enabling the detection of previously undetectable leaks.[2] This paper describes two cases of integrity failure in the B and C annuli detected by the new integrated high-precision temperature and spectral noise logging technique, or HPT-SNL.
Anti-Corrosion Performance of Polyaniline Modified Ferrites
Authors: Mittal Vikas , Chaudhry A. U. , Khan M. I. 
Published: November 2012

Abstract
In this work, spinel based zinc, nickel and zinc-nickel ferrites were synthesized and modified with oxidatively polymerized polyaniline-phosphate. The corrosion protection behavior of these polymer modified ferrites was investigated after formulating with acrylic primer and subsequent coating on carbon steel panels. Salt spray test revealed that among all the anticorrosion pigments, polyaniline modified zinc-nickel ferrites showed significantly improved anticorrosion properties. Incorporation of PANI modified zinc and nickel ferrites in the primer coatings also improved the anti-corrosion performance. Pure PANI coatings suffered from adhesion problems with the substrate, which were markedly improved when PANI layered ferrites were introduced in the coatings.
Public, Private, or Hybrid? What the Upstream Oil & Gas Industry Can Learn from Other Sectors about "the Cloud"
Authors: Perrons Robert K. , Hems Adam 
Published: November 2012

Abstract
Despite the compelling case for moving towards cloud computing, the upstream oil & gas industry faces several technical challenges—most notably, a pronounced emphasis on data security, a reliance on extremely large data sets, and significant legacy investments in information technology (IT) infrastructure—that make a full migration to the public cloud difficult at present. Private and hybrid cloud solutions have consequently emerged within the industry to yield as much benefit from cloud-based technologies as possible while working within these constraints. This paper argues, however, that the move to private and hybrid clouds will very likely prove only to be a temporary stepping stone in the industry's technological evolution. By presenting evidence from other market sectors that have faced similar challenges in their journey to the cloud, we propose that enabling technologies and conditions will probably fall into place in a way that makes the public cloud a far more attractive option for the upstream oil & gas industry in the years ahead. The paper concludes with a discussion about the implications of this projected shift towards the public cloud, and calls for more of the industry's services to be offered through cloud-based "apps."
Challenges in Developing Attic Oil under a Giant Gas Cap, Advances in Modelling and Completion Strategy, a Well Case
Authors: Xu Siqing , Kshada Ali , Mukhtar Muhammad , Abdou Medhat , Amiri Abdel Hameed , El Wazeer Fathy 
Published: November 2012

Abstract
The reservoir under consideration, Reservoir A of the Lower Cretaceous age, Kharaib formation is a complex giant carbonate reservoir within an onshore field in Abu Dhabi. Substantial volumes of oil remain to be developed from the Attic area directly underneath the giant gas cap. 4 Attic wells were drilled since 2005 and they have all experienced gas breakthrough. To better manage Attic well production and optimize attic development, one of the attic wells has been selected for a pilot to install Integral Control Valves (ICV). The aims and objectives are for down hole zonal gas production control leading to optimized single well recovery while respecting facilities gas handling constraints. In parallel, two long horizontal wells are being drilled next to the pilot well to test the alternative concept of low production drawdown for gas breakthrough control.
This paper presents the design and detailed modelling study carried out for the ICV pilot well and the two long horizontal wells.
The ICV pilot completion design is described. The technology include swellable packer, inflow control valve (ICV), fiber optic DTS (Distributed Temperature Sensing). The open hole will be segmented into 3 sections using fed through swellable packer technology to pass fiber optic lines and install one ICV gross each section. The overall aim is to enable well GOR control, reduce project cost, maximize production and minimize any future rig intervention cost of shutoff at specific section.
A detailed single well model was developed within the 3D full field model. The well model was history matched, including PLTs and saturation logging. For ICV installation planning, a full range of sensitivity and uncertainty analysis was performed to assess likely impact. In particular, the impact due to potential faulting/sub-seismic faults was assessed. The model was also used to define data acquisition planning post ICV installation
The early production performances from the ICV pilot well are presented. For the two long horizontal wells, well design considerations are presented.
Plan for continued monitoring of the 3 wells are shown, with the aim of helping to optimize attic oil development.
Best Practices of Asset Management Process Supported by Reliability Analysis
Authors: Al-Adwani Adnan Eid , Kapavarapu Venkata Madhusudana 
Published: November 2012

Abstract
Reliability engineering approach was selected for optimizing the Gas Dehydration unit performance in BS-140/150 facilities to meet Asset Management process supported by Reliability Analysis for Gas dehydration units. Event log data collected for the system from March 2008 to March 2011 was analyzed using weibull ++ event log portfolio. Reliability Block diagram was developed for the gas dehydration and glycol regeneration system. The failure/repair distribution parameters were derived from the event log analysis. Reliability, availability and Maintainability values were derived from the simulation of the block diagram in "Block Sim" software. Exponential model was used for the analysis; since the temperature increases exponentially when the glycol cooler performance degrades. This leads to major impact on moisture increases in the gas export. Fault Tree Analysis was carried out for entire gas dehydration functional failure. Objective of this FTA was to identify the basic equipment responsible for the functional failure.
Immiscible WAG Injection Pilots Performance and Lessons Learnt in Carbonate Reservoir. Onshore Abu Dhabi Oil Field, United Arab Emirates
Authors: Al-Shamsi Hanaa S. , Abdulrahman Abdul Samad , Al-Ameri Ammar F. , Al Katheeri Abdulla B. , Sajeel Kashif , Al-Yaqoubi Amena 
Published: November 2012

Abstract
This paper reviews the performance of two immiscible Water Alternating Gas (WAG) pilots in W Field located in onshore Abu Dhabi- UAE. The main oil bearing reservoirs in the W Field are in the X, Y, & Z Zones. In August 2007, a gas injection pilot in Zone X was converted to a three-month cycle WAG pilot. The next month, a water injection pilot in the same zone was also converted to a three-month cycle WAG (Water Alternating Gas) pilot. The gas, water and WAG injection pilots were designed to increase sweep efficiency and optimize oil recovery from Zone X. The pilots are due to fulfill their objectives by year end 2012. Extensive monitoring programs were implemented in order to assess the performance of the pilots. These programs included frequent pressure measurements (BHCIP, PBU and PFO), production testing, cased-hole logging (RST/CNT/RPM/TDT), Flagship-PLT, PNL and Tracer injection monitoring. The results of the monitoring programs and the lessons learnt are discussed in detail. These results form the basis for the development of Zone X full field development plan. Immiscible WAG injection for 5 years showed improvement in sweep efficiency and recovery in Zone X. Field development plan considered drilling 8 WAGs wells in near future.
Challenges and Opportunities in Sour Gas Developments
Authors: Verlaan Cor , vd Zwet Gerard 
Published: November 2012

Abstract
To satisfy the growing global gas demand more reservoirs with sour contaminants (up to 40% of H2S and significant CO2) will be developed. Worldwide more than 1600 TCF of Sour Gas is anticipated. Shell has more than 60 years of experience in sour gas processing, ranging from the first facilities installed in Jumping Pound, Canada, to recent projects under development in Kazakhstan and Oman. This paper will describe a number of challenges and opportunities associated with development of "sour" projects.
The fact that H2S is lethal at low concentrations and highly corrosive in the presence of CO2 and/or (salty) water indicates that safety is a main driver in these projects. It is of crucial importance that the H2S is contained and that plant integrity is assured through tightly controlled maintenance programs.
Product specificationsfor produced gas and hydrocarbon liquids are ever tightening and legislation on emissions are becoming more stringent. Deep removal of H2S and other sulphur components like mercaptans and carbonyl sulphide is required. This increases the complexity and therefore cost of the sour gas processing facilities, which must compete with production from sweet gas in the region/country or alternatives such as LNG import. Technology innovation as well as smart integration of technologies are essential for the cost effective development of sour gas assets ensuring all specifications and emission requirements are met. Several examples of these technology innovations will be presented in this paper.
Common asset modeling and data integration as a foundation for field surveillance and performance improvement
Authors: VERBRUGGE Eric , DELESALLE Hervé , HANSEN Ralph 
Published: November 2012

Abstract
By creating a common view on field operation data, harmonizing the language within a site and from site to site, it becomes possible to work from different locations towards common objectives, ensuring the same understanding of "what goes on" on site. This provides an opportunity for rethinking competences, roles and distribution of responsibilities within the organization.
Total has developed a methodology to build such a view, based on a "Common asset model" and a "Field Monitor Platform".
The "Common Asset Model" is a Rosetta Stone for field operations data; it contains a description of the field equipment that is comprehensible to engineers in all disciplines contributing to field performance management. The naming of equipment, the attached information, as well as the associated semantic metadata offer a clear vocabulary shared by everybody in the field. This ensures that data is used in a consistent and appropriate manner, according with its nature, its actual source, its time granularity, the process that has built it...
The "Field Monitor Platform" provides a unique entry point for end-user applications to access all field operation data actually stored in the multi-disciplinary IT systems. End-user applications could be monitoring tools, calculations, event handling or simulation tools. The system relies on virtual integration as it only holds pointers to data within its official repository and delivers it directly from the original source.
The Field Monitor Platform has been industrialized for use in Total fields operations with a first deployment in the Gulf of Guinea.
The main results of this effort are:
A new robust methodology to define and manage a common asset model An innovative IT system ensuring efficient data integration A clearer understanding of the detailed monitoring requirements of an asset in general, and of the nature of transverse decision making in particular.
Impact of Asphaltenes Deposition on Completion Design for CO2 Pilot in an Onshore Abu Dhabi Field
Authors: Abdallah Dalia 
Published: November 2012

Abstract
Gas injection is one of the most common methodologies for Enhanced Oil Recovery (EOR) in the oil and gas industry. One of the challenges associated with gas injection, e.g. natural gas, CO2 and N2, is potential asphaltenes precipitation and subsequent deposition causing blockage throughout the production system. It is crucial that precipitation of asphaltenes is identified early in the planning stage of any EOR project so that mitigation strategies are put in place to avoid negative impact on well performance.
A line-drive pattern CO2 pilot is planned in a super giant field A onshore Abu Dhabi and hence single phase bottomhole samples were collected from a nearby well to evaluate asphaltene stability under CO2 gas injection. This paper presents the results of the lab work that clearly indicate no asphaltene deposition problems during natural production; however, asphaltenes will precipitate when CO2 is mixed with the crude at mole fractions as low as 0.2. Based on the experimental results and on field results from another CO2 pilot in field B, which experienced asphaltene deposition problems, it was deemed necessary to include provisions for continuous downhole chemical injection of asphaltene inhibitors in the CO2 pilot producers for field A.
The challenge is to combine the requirements to prevent CO2 corrosion and to prevent asphaltene deposition in the well. The paper describes the different completion design options that can be used to achieve the desired target taking into account the cost impact. The designs incorporate combinations of different tubing materials and chemical injection options with pros and cons to using each, keeping in mind the reservoir monitoring requirements that can add more constraints to the completion design.
Pore Pressure Prediction Using High Resolution Velocity and Acoustic Impedance in a Complex Field
Authors: Thakur Ram Kumar , Angstadt David M. , Chakraborty Kalyan , Kelsch Ken D. 
Published: November 2012

Abstract
Pore pressure prediction for exploratory deep Paleozoic well to avoid kicks, blow-outs, borehole instability and to design safe mud weight during drilling phase is a major challenge due to unavailability of deep well informations in South Fuwaris field, Kuwait. The problem was resolved integrating acoustic impedance volume derived from innovative seismic inversion on Prestack 3D Q-Land seismic data and geomechanical model with deeper pore pressure trend from drilled well data.
The Q-land data with exceptionally clean, high signal to noise ratio, reliable amplitude, stable phase and wide range of frequency with high trace density facilitated reliable inversion for prediction of reservoir properties from seismic. The high resolution is achieved through global optimization to a single non-linear objective function, which provides the optimum positioning of the layers and 3D multi-trace damping of the random-noise. The low frequency model, a prerequisite for seismic inversion was built with densely sampled stacking velocity constraining on seismic horizons and wells.
The most popular Bower's method, accounts for Loading (under-compaction) and Unloading (fluid expansion ) was applied to estimate Bower's parameters by cross-plotting velocity against effective vertical stress for drilled well - "A". The velocity reversal at Sargelu formation was confirmed with kicks in this well which was also cross validated with nearby Humma wells.
The pore pressure and frac gradient were estimated along proposed exploratory well with the trend developed at known shallower well "A" which was found to be in conformity with regional trends. The lithology predicted along proposed boreholes in order to design mud weight plug and sanctity was reviewed at Top lithological markers using pseudo porosity logs derived with multi-attributes using neural network technique.
This paper presents an integrated approach of pore pressure prediction for drilling deep exploratory well to minimize drilling risks.