bluuebunny/crossref_metadata_2025_split huggingface dataset:
The First Successful Field Demonstration of Alkaline Surfactant and Polymer Flooding through Thin Layer
Authors: Cheng Jiecheng , Dianping Xu , Xinguang Sui , Hongwei Wang 
Published: November 2012

Abstract
The Alkaline Surfactant and Polymer (ASP) demonstration block has 49 injectors and 63 producers, with area of 1.92 km2. The target zone has bigger reservoir span and consists of many thin layers with narrow fluvial sand body, smaller thickness, lower permeability, higher clay contents. The layers combination and well spacing have been determined basing on the fine geological research and existing ASP flooding performance. The ASP formula, injection parameters and system slug combination are determined through the lab research and numerical simulation.
Field data show injection and production rate maintain an acceptable level at the decline of 7.91and 17.1% in volume respectively. Producers have good response with the average WC decreased from 96.2 to 78.6% for center wells. Profile measurements results show that, for higher permeable zone, the adsorbing thickness has been improved by 13.4 and 7.1% respectively by contrast to water and polymer flooding, and for lower permeable zone, it is 46.1 and 37.1 respectively. The analysis on produced oil shows that, during ASP injection process, the C16-38 content has increased gradually from51.9 to 63.7.This result indicates that the oil displacement efficiency has improved. The ultralow IFT between water phase and oil phase has been incounted, whose liquid was produced from 28 wells, which are among 36 total center wells. That states ultralow IFT has been achieved widely in the reservoir. At present, chase water has been injected, with WC 92.0% and incremental oil recovery 26.0% OOIP. The ultimate oil recovery predicted to be 28.0% OOIP with production cost at $24.6 / bbl.
Produced Water Re-Injection, a Successful Strategy, from Pilots to Field Wide Implementation
Authors: Katchi K. , Remfsío Luís , Abdullah Dalia 
Published: November 2012

Abstract
As ADCO's oil fields mature, produced water increases. ADCO forecasts that the produced water may increase in the next 25 years as much as 10 fold (in excess of 600,000 BWPD by 2020 and more than 1,000,000 BWPD by 2027). On the other hand, in order to support the reservoir pressure, ADCO is sourcing brackish water from deep aquifers (D, S and U). The produced water is then disposed back into aquifer S. This practice has high financial and environmental costs:
In order to strategically manage increasing volumes of produced water as the main oil producing reservoirs reach maturity, ADCO started pilots to re-inject untreated produced water in three fields in early 2000: Field 1 in 2002, Field 2 in 2010 and Field 2 in 2003.
Positive pilot results in Field 1 led to field wide expansion of the Produced Water Re-Injection (PWRI) into one the oil bearing reservoirs and it was included in the Full Field Development Plan (FFDP).
A pilot for re-injecting untreated PWRI is currently running in Field 2 for the past 16 months at a rate of more than 20,000 bwpd. Positive outcome so far led to raising funds to extend PWRI network to achieve re-injection rates of 50,000 BWPD into one of the oil bearing reservoirs in this field.
The pilot for Field 3 was plagued with interruptions since the start caused by PWRI system material integrity issues which did not allow concluding so far whether untreated PWRI re-injection into one of the oil bearing formations is achievable. In order to address this situation, corrosion mitigation measures both for relevant surface facilities and downhole completions are being implemented and in parallel, an integrated coreflood testing/geomechanical properties study is on-going to assess the degree of treatment required to allow re-injecting produced water cost effectively in the most permeable oil bearing reservoir in this field.
ADCO's approach to managing increased produced water rates through pilots and learning from rock matrices testing/studies shows that managing field wide PWRI systems in a cost effective and environment friendly manner is achievable if planned sufficiently in advance and executed properly.
Chemical Incompatibilities between Formation Water and Injection Water; Comparison between Modeling and Site Observations in Fields Operated by TOTAL
Authors: Baraka-Lokmane Salima , Hurtevent Christian 
Published: November 2012

Abstract
This study presents examples of fields operated by Total where are observed incompatibilities between reservoir formation water and injected seawater. In these examples, we show the scatter between risk estimated by modeling and site observations.
The prediction of calcium sulfate deposits identified by modeling is not valid as the scaling problems are either non-existent or considerably less serious than expected. With respect to the precipitation of barium sulfate, the risk estimated by modeling is always much higher than reality. In this study information are provided that will allow us to have more realistic scaling predictions in the future.
Permeability Scalar from Seismic-Based Fracture Prediction
Authors: Matarid Tarek , Afia Mohamed S , Al-Hossani Khalil I. , Amer Mohamed M. 
Published: November 2012

Abstract
The post stack seismic fracture prediction method consistently shows fractures that are similar to those indicated by well methods and therefore seismic can be used to detect natural fractures between wells. The confidence in the seismic fracture prediction method's ability to capture information about fracture in Carbonate reservoir has increased if the well data are accurately integrated.
This paper describes an approach in characterizing fractured reservoir of upper Jurassic Carbonate using seismic structure attribute maps. The ultimate objective of this study was to attempt to map permeability scalar inter-well for the contribution to the simulation model and the subsequent development plan of an oil field offshore Abu Dhabi.
The studied field is not developed, but the subject reservoir was sparsely sampled with logs, limited well tests, limited cores, one FMI and one full waveform sonic. We have studied and analyzed the well based fracture detection results. The well analysis included FMI study, Stoneley waveform, well production tests and core images. The likely fractured layers were identified at the lower dense part of the reservoir. Well seismic synthetics were generated and the fractured layers were found to exist in less than one cycle.
Following the fractured layers identification in the seismic cube, an intensive seismic attribute analysis was conducted. The studied seismic reservoir attributes includes spectral decomposition analysis of Amplitude and Phase followed by structure attributes such as Coherency, Curvature, Amplitude change in X or Y and Azimuth. Here we report and analyze the fracture prediction results for Carbonate reservoir.
A consensus results from borehole ellipticity, Seabed ramp and near Seabed seismic structure map versus known regional stress will be presented as guide of current stress direction. Based on the extracted fracture map from seismic, the current stress direction and the well permeability scalar, a 1km x 1km permeability scalar map was generated.
Innovative Modelling Method of Diagenetic Overprints in Carbonate Reservoirs
Authors: Planteblat Caroline , Massonnat Gérard , Virgone Aurélien , Caline Bruno , Pabian-Goyheneche Cécile 
Published: November 2012

Abstract
Modelling products of diagenetic processes in carbonate reservoirs is still a challenge since both stochastic and physicochemical simulations cannot easily reproduce complexity of features generated by those processes. An alternative way to modelling diagenetic overprints deals with an innovative methodology based on process-like simulation of the fluid-rock interaction and its effects on reservoir properties. The principle of the method is related to a lattice gas automata used to mimic the diagenetic fluid flows and to reproduce the diagenesis effects through the evolution of both mineralogical composition and petrophysical properties.
This new modelling approach is well adapted to handle dolomitization processes and was applied on two case studies.
In the Urgonian carbonates, (Barremian-early Aptian) characterized by a platform facies predominantly of rudists and bioclastic/ooid grainstone (S.E. France), five main diagenetic stages have been identified. The 2D modelling focuses on dedolomitization features located on parasequence boundaries.
In the Venetian platform (Lias, N.E. Italy), data collected show four diagenetic stages. The main one, related to dolomitization along fractures, is called per-ascensum dolomitization. Three of the diagenetic stages have been simulated on a 3D depositional model previously filled with initial facies and original petrophysical properties.
The simulations of the Urgonian series lead to generate dedolomitized bodies related to surface boundaries that match those identified on the outcrop. Calibration on actual data of diagenetic parameters used for per-ascensum dolomitization modelling of the Venetian platform also enables to reproduce and to visualize the displacement of dolomitizing fluids in the fracture network and within the stratigraphical layers.
In both cases, the evolution of the mimetic diagenetic fluid effects on mineralogical composition property can be followed through space and numerical time, which helps to understand the heterogeneity of reservoir properties.
This method enables the modelling of diagenetic overprints without any explicit physicochemical equation in any carbonate reservoir for which diagenetic products are generated through fluid transport.
Under-Balanced Drilling: A Game-Changing Technology for the Development Strategy of a Giant Carbonate Reservoir
Authors: Khan Karim , Aziz Khalid Abdel , El Baramawi Mohamed , Mueller Klaus , Mata Tomas , Al Hassani Khaled 
Published: November 2012

Abstract
It is fundamental to pilot and deploy IOR/EOR initiatives to improve recovery from petroleum reservoirs using cost effective methods, ensuring a continuous supply of production that would meet the ever-increasing demand for energy.
Under-Balanced Drilling (UBD) technology proved worthy as a valuable initiative in the redevelopment strategy of a Giant Carbonate reservoir located in the Middle East. It improved well deliverability especially in low permeability reservoir zones. The strategy for this has been to deploy 3-4000 feet laterals to maximize reservoir contact to such tight units or drill as far as possible to have maximum flow input/productivity. Horizontalization (non-UBD), together with stimulation has been going on for many years with mixed success as recent production log surveys showed negligible contribution from several wells completed in these low permeability units.
In 2011, well-X was drilled underbalanced to assess the value of this technology in augmenting productivity and improving reservoir characterization. Significant improvement in Productivity Index was accomplished by minimizing damage from drilling and completion operations. In addition, considerable knowledge was acquired from Flowing While Drilling (FWD) data and multi-rate tests in four segments of the production zone. Real-time geosteering was actively used to account for changes in the reservoir architecture.
Analysis of the FWD data has derived in new understanding of the dynamic nature of the reservoir's South-central region, highlighting sectors of high permeability, fractures, tight areas, different pressure regimes and varying fluid composition. Furthermore, despite the innovative nature of the technology, drilling and completion was very well controlled by the Well Construction teams, resulting in costs not significantly higher than normal over-balanced wells.
The enhanced reservoir knowledge that UBD delivers as shown from well-X will result in improved recovery efficiency and possible delayed water production. Moreover, it is a lead value improvement technology that will meet strategic business objectives with minimum risk and lowest Unit Technical Cost.
Facies Characteristics of Aptian Formation within the Regional Stratigraphic Framework of a Giant Carbonate Field in the Middle East
Authors: El Wazir Zinhom , Al Madani Noura , Müller Klaus 
Published: November 2012

Abstract
Facies and their distribution in space are key building blocks to determine the depositional architecture of hydrocarbon reservoirs. For this reason, the unified high resolution facies and sequence stratigraphy boundaries are needed to constrain facies architecture and their properties distribution for constructing the 3D static and dynamic model. A comprehensive facies analysis and modeling within the established stratigraphic framework, was conducted to reduce the uncertainty in correlating and building-up the architecture between wells.
Over 30,000ft of core data from 155 wells and their log data are used in integration with the seismic interpretation. Knowledge of the facies results in a better correlation, used then to generate a total of 47 spatial facies maps. Some facies are combined to facies associations (FA) maps, representing the FA at each sequence boundary in its sequence package. For each selected interval, the dominant FA observed in individual wells has been correlated; preserving the general evolution of the depositional environment and the sequence stratigraphy framework. These maps are used to constrain the variograms for the petrophysical properties distribution in terms of orientation and ranges.
A conceptual facies model was created based on facies distribution following an evolving platform to basin topography during transgressive (Apt1&Apt2), early-highstand (Apt3), late-highstand (Apt4a&Apt4b), and composite lowstand (Apt5) phases of carbonate platform development during the Aptian. The best reservoir quality is dominated by dissolution related mouldic and vuggy macropores. The grain supported textures demonstrate better overall reservoir quality as a result of more abundant interparticle and intraparticle pores and enhanced macro-vuggy porosity created by leaching process. Some poor reservoir quality is observed in grainy facies due to cementation.
A detailed understanding of the core-based facies description/analysis is required for identifying the reservoir properties and its relation to rock-texture; leading consequently to the rock-flow-units in the dynamic model.
Human Factors in HSE Performance
Authors: Misra Achal 
Published: November 2012

Abstract
‘Safety First,’ the motto of petroleum industry has been in focus since early 20th century evolving HSE considerably and as of today, we have industry best HSE practices nevertheless accidents still happen. A welder lost his life after he entered inside a 30" pipe to inspect a weld joint. This is despite safety alert being widely circulated two weeks prior for a similar accident happened elsewhere. Are accidents inevitable or preventable?
‘Preventable,’ would be the intuit answer but when prodded deeply with a psychological perspective the scenario apparently leaves an ounce of doubt, ‘was it inevitable?’ To demystify the fatalistic thinking, a psychoanalyst's perspective is required to unveil the latent human factors that lead to unsafe acts. Even the safety regulations cannot rein human decision making processes which are affected by cognitive biases such as intuition, overconfidence, illusion of control, confirmation, complacence and hindsight. Under such constraints, it is no surprise that incidents reoccur whereas companies search for compliance gaps in HSE implementation.
Taking into account the case study of fatal welder accident, this papers explores human error and its influence on performance level, unveils human brain functioning, describe briefly five cognitive biases that influences unsafe acts, conjure the fatal welder accident with plausible biases, and concludes calling for more efforts to increase the awareness of cognitive biases and develop a safety culture helping to prevent incidents and improve HSE performances.
China's Early Stage Marine Shale Play Exploration: A Deep Asia Pacific Region Horizontal Multiple-Stage Frac: Case History, Operation, and Execution
Authors: Lv Zonggang , Wang Lin , Deng Sufen , Chong King Kwee , Wooley James S. , Wang Qiang , Ji Peng (Marks) 
Published: November 2012

Abstract
During the past five years, shale gas developments have changed the game for the US natural gas industry. Globally, shale exploration activities are also increasing. China is in the early stages of exploiting the world's largest reserves of shale gas resources while attempting to cope with increasing energy demands.
This paper presents a case history of applicable technology currently used in North America for initial attempts at shale gas exploration in China. This case study is the first Cambrian age marine shale well in the Qiongzhusi formation located in the shale-gas-rich Sichuan province.
Many technologies were brought from North American shale gas applications for this well (Chong et al. 2010). This study describes the technologies used to drill and complete the targeted shale gas formation and guide the completion and stimulation design. The target formation was drilled horizontally and the casing was cemented. The formation was then stimulated with multiple stages after full integration of data from geologic, geomechanical, petrophysical, and core analysis, which aided in the fluid and proppant selection, proppant concentration, and the designed injection rate. A diagnostic fracture injection test (DFIT) was performed before the main treatment to confirm fracture gradient, closure, pore pressure, system permeability, and leakoff. Microseismic mapping was also used, which proved to be valuable when planning and assessing the fracturing results.
Currently, the well is flowing gas at rates comparable to early production time in a typical North American shale gas well with a similar type of completion.
This case study serves as an example of successful implementation of proven technology outside of the North America shale gas market. Continued projects such as this one are the predecessor to full-scale development of shale gas and have helped shape the abundant gas supply currently in the United States. Additionally, these types of projects are necessary to help China improve their future outlook on gas supply.
Best Practices in Turnaround Management
Authors: Festus Roy 
Published: November 2012

Abstract
1.Introduction
One of the Best Practice in Turnaround (TAR) Management is to have an effective system in place to monitor TAR Performance. Balanced Score Card (BSC) is an effective tool for measuring performance of a TAR project from different project perspective considering all management objectives.
2.NEED FOR BSC:
Today business is being done in a very competitive environment. ■ HSEQ standards are very stringent. ■ Compliance to Environment standard is very important. ■ Negligence, lack of knowledge and oversight is not acceptable. ■ Business needs to be carried out with SMART Targets (Specific, Measurable, Achievable, Realistic, Time bound). ■ Performance needs to be evaluated at every step from all project perspectives and management objectives.
To enssure excellence in TAR management, Takreer adopts BSC concept to evaluate TAR performance. This BSC incorporates all TAR objectives like inventory optimization, material availability, timely award of Contract, timely completion, quality and cost control with prime emphasis on HSE. The performance can be graphically represented as shown in slide – 2 of the presentation.
No technique will work unless you believe in it, own it and each individual makes it a part of his belief system.
Reducing Energy and Emissions through Predictive Performance Monitoring System
Authors: Zamzam Montaser M. , Reddy Vijaya B. , Al Bisher Khalid , Mather Ian 
Published: November 2012

Abstract
Air emissions from combustion sources are monitored by different techniques such as use of emission factors, engineering calculations, periodic stack monitoring, Continuous Emission Monitoring Systems (CEMS) and Predictive Emission Monitoring System (PEMS). CEMS despite being seen as best practice but is expensive and requires extensive maintenance. PEMS has become recently popular in estimating real-time emissions from various air pollution sources using measured process parameters. Abu Dhabi Company for Onshore Oil Operations (ADCO) based on a wide techno-economical survey had chosen PEMS to monitor its emission and maintain compliance report on air quality as per the requirements of Abu Dhabi National Oil Company ADNOC. In addition, ADCO's innovation ensured additional modules to monitor energy performance and also provide a platform for maintaining energy and emission KPIs. ADCO commissioned the first pilot PEMS in Bab field in 2010 covering all emission sources and typical units of the major energy users such as gas turbines, heaters, oil export pumps, water injection pumps and gas compressors.
PEMS real-time information and remote access through web helped in taking prompt corrective actions to control equipments and optimize use of fuel which resulted in subsequent reduction of energy and Green House Gases (GHG) emissions besides compliance assurance against ADNOC's air emission limits for process units. PEMS was proven to be as accurate as the hardware based CEMS over the entire range of operations and therefore it can be readily applied for tracking air emissions and energy efficiency from gas turbines, heaters at marginal cost. In addition to providing data for emissions compliance, ADCO was able to use the PEMS to optimize machinery operation for better performance and efficiency, and consequently reduced emissions.
This paper demonstrates ADCO's success in integrating energy performance and emissions reporting in one simple yet effective solution. The paper further describes how the PEMS was able to integrate data from various plant sources into one reporting system while at the same time meeting ADCO IT protocol.
Modeling of Asphaltene Precipitation in Heavy Oil Reservoirs Using Hydrate-Flory-Huggins Model
Authors: Nikookar M. , Sahranavard L. , Roayaei E. , Emadi M. A. , Pazuki G. R. 
Published: November 2012

Abstract
In this study, an equation of state (EOS) was developed based on volume correlation in predicting phase behavior of pure fluids. The Average Absolute Deviations (AAD %) of the modified EOS are 1.116, 4.318 and 2.93 for the saturated pressure, liquid density and vapor volume, respectively. The results of the proposed EOS are compared with those of Peng-Robinson (PR) and Modified Peng-Robinson (M-PR) equations of state. In the next step, the modified EOS was coupled with the hydrate-Flory-Huggins Gibbs energy model in order to predict asphaltene precipitation phase behavior in the crude oil. The results show that the hydrate-Flory-Huggins model can more accurately predict asphaltene precipitation than the original Flory-Huggins model.