bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drilling through Abnormally High- and Low-Pressured Compartments in the Bolontiku Offshore Field
Authors: Ramirez Silvestre , Ramirez Ricardo , Alvarez Eduardo , Bevilacqua Simon , Barrera Guillermo , Leon Renier , Leal Miguel , Padilla Jose , Elias Salvador , Martinez Erik 
Published: November 2012

Abstract
The Bolontiku field is located offshore on the continental shelf of the Gulf of Mexico, adjacent to the coast of Tabasco state. This field is composed of dolomitized carbonates of the Upper Jurassic Kimmeridgian formations, which yields 39° API hydrocarbons. Exploitation has dropped the bottomhole pressures from 8,159 psi to 5,600 psi and has created an average operating drilling window of 0.07 g/cm3. Such a narrow operating window increases the technical difficulty for continued development in this mature field using conventional drilling techniques. The complexity of effectively controlling the wellbore pressure has resulted in an endless cycle of fluid loss to formation, kicks, and well control events that translate into non-productive time (NPT), which increased operating time and costs, potentially leading to well abandonment.
A managed pressure drilling (MPD) technique allows for effective control of the pressure profile throughout the wellbore, identifying the bottomhole pressure (BHP) limits and applying appropriate backpressure accordingly. Owing to its efficiency, this technique has evolved from an innovative technology to become a required application to mitigate the inherent wellbore pressure problems associated with conventional drilling. Therefore, as MPD evolves, different approaches for well control evolve for kick events.
This paper describes a well-control application simultaneous to the drilling operation using MPD with a closed-loop pressurized control system. This paper reviews a case history of two wells that were drilled with MPD and compares results against three wells that were conventionally drilled in the Bolontiku field. MPD and simultaneous well control allowed for drilling the Bolontiku 37 well, which consisted of compartmentalized pressure that historically lead to fluid losses and water influxes. Therefore, it was possible to drill through zones that before were not technically possible.
Downhole Tool Tracking Software Significantly Improves Equipment Readiness, Utilization, and Reliability of Coiled-Tubing Operations in Malaysia
Authors: Connell Charles , Lyashkov Victor , Yunda Maria , Morrison Richard 
Published: November 2012

Abstract
Substantial improvement in gathering and managing critical data in tracking, readiness, utilization and reliability of downhole tools is required in today's challenging well intervention operations. Critical information must be collected and presented in an effective way in order to make efficient use of that data. Coiled tubing service providers have already achieved successes in the maintenance tracking of surface equipment but not for downhole tools. Whereas running conventional coiled tubing tools ranged from check valves, nozzles, motors and jars, today's coiled tubing tools incorporate advanced electronics, fiber optics and sensors. The intent of the following discussion is to show how the implementation of software, customized for coiled tubing downhole tools, resulted in an improvement in service quality.
The software was pilot tested in Malaysia's coiled tubing operations and has shown significant improvements over existing methods of tracking tool utilization and maintenance. The features and improvements found in the newly implemented software, such as the automatic triggering of maintenance events based on job conditions, will be discussed and compared to the existing methods available for tracking and using critical information.
Implementation of the software in 2011-12 has allowed a step-change in Malaysia's maintenance practices almost 500 downhole tools, ensuring the highest level of service quality. The data captured by the system also feedbacks to the engineering and sustaining departments where known issues can be communicated to the rest of the CT population or design improvements can be identified and implemented. The results of the pilot program in Malaysia have led to improvements in the system which is now being rolled out to all coiled tubing locations worldwide targeting best in class service quality.
Streamed Workflow for Static Model Uncertainty Evaluation of Carbonate Reservoir in an Offshore Abu Dhabi Field
Authors: Al Hossani Khalil , Sayed Mohamed I. , Matarid Tarek , Al-Harbi Haifa , Walia Samir , Essam Mohamed , Kumar Amit 
Published: November 2012

Abstract
Defining the range of uncertainty is a crucial part in the oil field development particularly for carbonate reservoirs that have limited well data and with the absence of dynamic data. It is very important to develop an in-depth understanding of the range of uncertainty of all reservoirs parameters such as:
- Structure uncertainty - Lithofacies and reservoir rock types - Static reservoir attributes population technique (Porosity, Permeability, & Water Saturation)
Although outcrops and analogs are often employed to define reservoirs model parameters, it is still challenging to define and agree on the relationship between modeling parameters and their distribution ranges.
This paper addresses the impact of uncertainty of different modeling parameters on the volumetric calculations and full field development scenarios starting with structure model. Various areal and vertical uncertainties were investigated to set the structure uncertainty ranges. Then, the identified depositional environment models were used as guides to set the uncertainty ranges for each lithofacies association. The reservoir rock types were directly affected by both structure and lithofacies association models. Different ranges of variations were used for each rock type within each reservoir layer to ensure capturing the lateral and vertical reservoir heterogeneity and to propose multi distribution scenarios for each reservoir tock type within non-cored intervals/areas.
The petrophysical parameters were conditioned to the reservoir rock types model. So, they were directly affected by multi scenarios of RRT models.
In conclusion, 20 volumetric estimates were calculated and evaluated to define the probabilistic scenarios P10, P50, and P90 that will be used to investigate the full field development scenarios.
Phase Behavior and Displacement Characteristics for CO2 EOR with a Reservoir Fluid from a Middle Eastern Offshore Reservoir
Authors: Takahashi Satoru , Okabe Hiroshi , Mitsuishi Hiroshi , Kawahara Hiroshi , Al-Shehhi Hamad Rashed , Al-Hammadi Hamdan Mohamed 
Published: November 2012

Abstract
This describes the results of extensive phase behavior and slim-tube analyses for CO2 EOR study in a Middle Eastern offshore reservoir. The objectives of this study are to evaluate the effectiveness of CO2 injection to the target reservoir and to reduce uncertainties based on laboratory and simulation studies. This study is focused on solubility and slim-tube tests in the laboratory studies, and its analyses using an equation of state (EOS) model that reproduces the majority of conventional PVT and solubility swelling results for an associated hydrocarbon gas and oil system.
We performed conventional PVT and solubility swelling tests for a CO2-Oil system successfully. With the results of solubility tests, an EOS model was established and tuned for predicting the solubility behavior in the mixing fluid between CO2 and the target reservoir oil within sufficiently acceptable ranges. In addition, we conducted a series of slim-tube tests with CO2 and a synthetic hydrocarbon gas, which is similar compositions to the associated hydrocarbon gas, at some pressure levels. In comparison between CO2 and the synthetic hydrocarbon gas injection, there is a significant difference of oil recovery at relatively low pressure, indicating that CO2 injection is more effective than the synthetic hydrocarbon gas injection. Results of slim-tube tests with CO2 show that the oil recovery reaches greater than 90% at any pressure level, but the displacements of oil at the outlet of slim-tube by the visual cell observations appear in different manners.
We simulated slim-tube tests with the adequate EOS model for CO2 injection under carefully arranged simulation conditions. As a result, we confirmed that simulated gas saturation and k-value profiles are consistent with the visual cell observations, and this displacement of oil by CO2 is characterized as condensing/vaporizing drive. These results confirm the effectiveness of CO2 injection to the target reservoir and lessen the uncertainties of fluid interaction at the laboratory scale.
Offshore Drilling Waste Discharge: Egyptian Environmental Regulations
Authors: Agwa Ahmad , Sadiq Rehan , Leheta Heba 
Published: November 2012

Abstract
Egypt is located in the Northeast of Africa where oil and gas (O&G) are produced offshore from the Gulf of Suez and the Southeast part of the Mediterranean. The O&G production in Egypt is distributed as follows: 70% Gulf of Suez, 16% Western desert, 8% Sinai Peninsula and 6% Eastern desert. Past O&G activities, refining and transport have resulted in chronic pollution in Egyptian offshore, and numerous environmental programs have been initiated to protect new development areas from the environmental impacts. The offshore drilling process uses drilling fluids (muds) and generates waste fluids and cuttings, which could be the largest discharges going into the receiving water bodies. Water-based drilling fluids are commonly employed for drilling in Egyptian offshore because of their expected environmental benign behavior in the marine environment. The main objective of this paper is to highlight relevant Egyptian environmental regulations and explain several options to manage offshore drilling wastes: offshore discharge, offshore down-hole injection and onshore disposal.
GeoTime™: A Novel, Automatic 3D Chronostratigraphic Seismic Interpretation Methodology for Complex Geological Settings
Authors: Keskes Noomane , Yin Yahui , Gallon Jonathan , Al Shekaili Fatema 
Published: November 2012

Abstract
Chronostratigraphic seismic interpretation provides insights into basinal evolution. By mapping the internal stratigraphic architecture, this method has been widely used for well placement optimization and reservoir model building.
Over many years of research at TOTAL, the Sismage team has created GeoTime™, a software tool for automatic chronostratigraphic analysis of seismic data, particularly in complex geological settings. This tool can be used to automatically or semi-automatically track the chronostratigraphic surfaces. The output is a 3D cube of stratigraphic surfaces (iso-geological time) which can be used to build the frame work for geomodels. A 3D cube of "Wheeler Diagram" is also obtained by segmenting the seismic volume into different depositional or non-depositional packages. This diagram provides better understanding on the spatial distribution of deposition through the geological time.
In this paper, we will firstly introduce the GeoTime™ methodology, and then demonstrate two application examples. The first example is taken at a regional scale, where GeoTime™ was used to automatically track the major stratigraphic surfaces within a first order progradation system. The seismic volume was then segmented into sub order sequences bounded by the automatically tracked surfaces. 3D Wheeler diagram was also constructed to understand the depositional history. The second example is taken at reservoir scale from a producing field with more than 800 borehole penetration. In this example, we imposed geological constraint into the GeoTime™ workflow, and improved the previous interpretation of higher order prograding clinoforms for placing new development wells.
Simulating Early Gas Breakthrough in Undersaturated Oil Using Alpha-Factors
Authors: Bourgeois Marcel J. , Gommard Denis R. , Gouas Halim 
Published: November 2012

Abstract
A method is proposed for reproducing early gas breakthrough when performing full-field compositional simulation of gas injection in under-saturated oil. It was developed by solving the successive problems encountered on a real heterogeneous field with a gas injection pilot
The first problem was to correctly model transport in this large carbonate field using a coarse grid. It was dealt with by using alpha-factors.
The second difficulty was related to the strong under-saturation of the oil: all injected gas dissolves until saturation pressure reaches actual block pressure. In practice, this means that gas will appear too late in the simulation. This is easily avoidable in black-oil simulation, but compositional simulators will usually not allow to circumvent the equation of state. We found out that correcting the critical transition allowed to speed up the appearance of the gas phase.
A third difficulty was to history match the gas injection pilot without distorting the geological model. We thus wanted to reproduce the inherent instability of gas injection, which had not swept all layers homogeneously, as shown by time-lapse RST data. This problem was solved using an extra-capability of alpha-factors: stating that the transported fluid viscosity is lower than average grid-block viscosity, and integrating this new correction into the oil and gas alpha-factor table, allowed to successfully reproduce quick gas encroachment in permeable layers.
The fourth task of imposing a residual oil saturation Sorm was solved using the end-point of the alpha-factor table.
Thus we propose a method for correcting several effects simultaneously: acceleration of the light components, acceleration of the critical transition from volatile oil to gas condensate, viscosity correction to reproduce gas fingering, and slow-down of the heavy components in order to force residual oil saturation. To our knowledge, documentation of the second and third corrections is new. All four corrections being justified, we used them all in a composite alpha-factor table.
Laboratory Investigation of Low Salinity Waterflooding for Carbonate Reservoirs
Authors: Al-Harrasi Amira S. , Al-Maamari Rashid S. , Masalmeh Shehadeh 
Published: November 2012

Abstract
Low salinity waterflooding (LSF) research has been gaining more momentum in recent years for both sandstone and carbonate reservoirs. Published laboratory data and field tests have shown an increase in oil recovery by changing injected brine salinity, especially for sandstone reservoirs. It is widely accepted that low salinity water alters the wettability of the reservoir rock from less to more water-wet conditions, oil is then released from rock surfaces and recovery is increased. The main objectives of the current study are to: test the potential of increasing oil recovery by LSF of a carbonate reservoir and to investigate the factors that control it. The impact of LSF on oil recovery was investigated by conducting coreflood and spontaneous imbibition experiments at 70 °C using core samples from a carbonate reservoir, crude oil and synthetic brine (194,450 ppm) which was mixed with distilled water in four proportions twice, 5 times, 10 times and 100 times dilution brines. Moreover, both crude oil/brine interfacial tension measurements (IFT) and ionic exchange experiments were carried out at room temperature (25 °C).
The results of the study show higher oil recovery as a result of reducing injected water salinity in both coreflood and spontaneous imbibition experiments. Coreflood experiments showed an increase in oil recovery by 3 to 5 % of OOIP, while spontaneous imbibition experiments showed an increased by 16 to 21 %. Additionally, spontaneous imbibition experiments provide direct evidence of wettability change by the LSF. The study also shows that the increase in oil recovery was obtained at much higher water salinity than the one observed in the case of sandstone rock.
Experimental Investigation of Wet Gas Dew Point Pressure Change with Carbon Dioxide Concentration
Authors: Odi U. , El Hajj H. , Gupta A. 
Published: November 2012

Abstract
Dew point pressure is a critical measurement for any wet gas reservoir. Condensate blockage is likely when the reservoir pressure decreases below the dew point pressure and this can result in a reduction of gas productivity. Errors in measuring dew point pressure can lead to errors in the estimation of the onset of condensate blockage and thus be detrimental to the management of wet gas fields. This work presents experimental verification of a new method of determining dew point pressures for wet gas fluids. Results obtained from this method are compared to calculated values based on Peng Robinson equation of state.
Dew point pressure determination is important when devising solutions on how to prevent condensate blockage. One possible treatment fluid, carbon dioxide, has the ability to lower dew point pressures and thus delay the onset of condensate blockage. The novel method presented in this work was applied to determine the experimental dew point pressure of several wet gas mixtures as a function of carbon dioxide concentration. These experiments also show the potential of using carbon dioxide to lower dew point pressures in wet gas fields.
Experimental results show close match between the experimental estimates of dew point pressure and the Peng Robinson calculations. Experimental results also support the general observation that carbon dioxide has the ability to lower the dew point pressure of wet gas fields.
The results of this work are useful in Enhanced Oil/Gas Recovery processes that utilize carbon dioxide and for Huff and Puff which uses carbon dioxide to remove and prevent further build-up of condensate banks in wet gas reservoirs. This work investigates experimental conditions showing the change in dew point pressure as a function of carbon dioxide concentration. This dynamic relationship can be used to tune equation of state models which, in turn, allows more accurate reservoir modeling of hydrocarbon recovery process.
Developing High Resolution Static and Dynamic Models for Waterflood History Matching and EOR Evaluation of a Middle Eastern Carbonate Reservoir
Authors: Masalmeh S. K. , Wei Lingli , Hillgartner H. , Al-Mjeni R. , Blom C. 
Published: November 2012

Abstract
Enhanced oil recovery (EOR) has become increasingly important to maintain and extend the production plateaus of existing oil reservoirs. Simulation models for EOR studies require the right level of spatial resolution to capture reservoir heterogeneity. Data acquired from the dedicated observation wells are essential in defining the required resolution to capture reservoir heterogeneity. For giant reservoirs with long production history, their full field models usually have grid block sizes that are of similar scale as the distance between injectors and observation wells, with the consequence of losing the value of the time lapse saturation logs from dedicated observation wells. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must.
The objective of this paper is to present an improved and integrated reservoir characterization, modelling and water and gas injection history matching procedure of a giant Cretaceous carbonate reservoir in the Middle East. The applied workflow integrates geological, petrophysical, and dynamic data in order to understand the production history and the remaining oil saturation distribution in the reservoir. Large amounts of field data, including time lapse saturation logs from observation wells, have been collected over the last decades to provide insight into the sweep efficiency and flow paths of the injected water.
Iterative simulations were performed to investigate different scenarios and various sensitivities with each iteration involving an update of the static model to honor both the dynamic and core/log data. While applying this iterative process it was also acknowledged that conventional core data (e.g. 1 plug per foot) may not capture the high permeability streaks in these heterogeneous reservoirs that control much of the reservoir flow behaviour, hence much denser plugging and core examination is required. In addition, permeability upscaling procedures need to take into account the fact that core plugs may not represent the effective permeability of the larger connected vuggy pore systems.
The improved understanding of reservoir heterogeneity, the more robust reservoir characterization, and the improved history matching demonstrates that a better representation of reservoir dynamics is achieved. This provides a solid platform for designing and planning future EOR schemes.
Quantitative Risk Analysis of Spillage in a Petroleum Pipeline
Authors: Dawotola Alex W. 
Published: November 2012

Abstract
A methodology for quantitative risk assessment of petroleum pipeline has been presented and applied in this paper. The proposed methodology consists of both the analysis of probability of failure and the consequences of fatalities are analysed using commercial software CANARY v.4.2. Based on the outcome of probability of failure and consequences, the individual and societal risk of pipeline is then estimated. The time of presence of an individual in the hazardous zone is taken into account during calculations of the individual risk. Societal risk is represented by an F-N plot that defines the relationship between frequency and the number of people suffering from fire and explosion due to fuel spills. Both individual and societal risks are modelled using SAFETI FX 6.5.1 software by DNV. The methodology is capable of analysing quantitative risk of any pipeline, irrespective of location. The approach has been applied to conduct quantitative risk assessment as well as study the differences in consequences and risks arising from the failure of gasoline and natural gas pipelines. The methodology is robust and can be broadened to cover different failure factors.
Azimuthal Velocity Analysis for Anisotropic, Laterally Heterogeneous Media
Authors: Takanashi Mamoru 
Published: November 2012

Abstract
Azimuthal velocity analysis from multi-azimuth seismic data is increasingly used for predicting the horizontal stress and fracture distribution. However, seismic velocity can be strongly influenced by small-scale lateral heterogeneity associated with channels and carbonate reefs embedded in the overburden. Here, I review discussion about the influence of a thin, laterally heterogeneous (LH) layer on the normal moveout (NMO) velocity and NMO ellipse (azimuthally varying normal-moveout velocity) for horizontally stratified anisotropic media. The distortion of the medium parameters is caused primarily by quadratic lateral variation (i.e. curvature) of interval vertical traveltimes, and the errors increase with the distance between the target and the LH layer. Moreover, the Dix-type method can significantly amplify the lens-induced distortion in the interval NMO velocity. Using the analytic result, I propose a quick approach to correct the influence of lateral heterogeneity for a gently-dipping overburden, which is suitable to many regions such as the Middle East. The developed approach should contribute to more accurate evaluation of hydrocarbon reserves, better planning of well locations, and optimization of development plans for fractured reservoirs.