bluuebunny/crossref_metadata_2025 huggingface dataset:
Best Safety Practices for New Drilling Rigs, ADCO's Successful Precautions Approach
Authors: Karrani Sultan Mohamed , Boucif Mustapha Nasreddine , Carvalho Rui , Kuyken Chris , Kerr Brad
Published: November 2012

Abu Dhabi Company for Onshore Oil Operations (ADCO) has recorded the lowest Total Recordable Case Frequency (TRCF) of 0.52 in its history. This is also a drilling worldwide record and it was achieved, despite ADCO have increased its drilling fleet by around 30%. This successful score could not have been achieved without proper planning and implementation of the new rigs, especially with limited resources and through very tight schedule to meet ADCO's business plan requirements.

An assessment to our project leads us to collect all the inputs related to the best way for the safe start up of the rigs. Taking in consideration the changes in design and shortage in crew staff, we have built a detailed plan for the safe start up rigs with all the parameters such as human recourses, management involvement, and technical inspections. Furthermore, we have developed plan to be in three stages: commissioning, rig move, and rig spud for the first well. Being HSE the focus with the start up of the new rigs, the main challenge faced by the project team was to ensure the implementation of every step in our HSE plan. This allowed us to safely start up the new rigs while delivering the required operational performance despite the fact of staffing the rigs with about 50% green hats crews. For both operator and contractor, the responsibility for safety, health of workers and environment has increased due to considerable impact of strategic growth plans and additional workload. For the major projects like rig expansion we have applied the best functional planning for safety management system.

This paper will discuss and review the methodology for the rig start up plan and implementation of the primary actions needed to be developed and monitored through minimizing the risk and the impact to the project cost and schedule. Success, failures, and lessons learned are highlighted through the sections in order that full knowledge of the current project is captured and mitigated in the ongoing expansion with additional rigs being ordered. This will enable ADCO to enhance HSE commitments ensuring new rigs are delivered ahead of time.
Flotation, Filtration, and Adsorption Pilot Trials for Oilfield Produced Water Treatment
Authors: Al-Maamari Rashid S. , Sueyoshi Mark , Tasaki Masaharu , Okamura Kazuo , Al-Lawati Yasmeen , Nabulsi Randa , Al-Battashi Mundhir
Published: November 2012

As an oil field matures, it produces larger quantities of produced water. Appropriate treatment levels and technologies depend on a number of factors such as disposal methods or reutilization aims, environmental impacts, and economics

In this study, a pilot plant of capacity 50 m3·day−1 was utilized to conduct flotation, filtration, and adsorption trials for produced water treatment at a crude oil gathering facility. The plant's flexible design allows for the testing of different combinations of these processes based on the requirements of the water to be treated. The subject water during this study was a complex and changing mixture of brine and oil from different oilfields.

Induced gas flotation trials were conducted, with different coagulant (poly-aluminum chloride or PAC) addition rates from 0-820 mg·L−1. Inlet oil-in-water (OIW) concentrations were quite varied during the trials, ranging from 39-279 mg·L−1(fluorescence analysis method) and 12-340 mg·L−1 (infrared analysis method). Turbidity also varied, ranging from 85-279 FTU. Through flocculation/coagulation and flotation, dispersed oils were removed from the water. PAC addition ranging from 60-185 mg·L−1 resulted in reduction of dispersed oil concentration to below 50 mg·L−1 in treated water. PAC addition ranging from 101-200 mg·L−1 resulted in reduction of dispersed oil concentration below 15 mg·L−1 in treated water. Turbidity was also reduced through flotation, trial average reductions ranging from 57-78%. Filtration further reduced turbidity at rates above 80% through the removal of any suspended solids remaining from flotation. Activated carbon adsorption reduced OIW concentrations of flotation/filtration treated water to 5 mg·L−1 through the removal of dissolved oil remaining in the water. Results confirmed that such adsorption treatment would be more practical for water with lower COD concentration, due to high COD concentrations in water drastically reducing the lifetime of activated carbon.
Optimization of Effective Horizontal Length Utilizing Underbalanced Technique
Authors: Al Menhali Adnan Mohammed , Belhaj Hadi
Published: November 2012

Over the last two decades, horizontal wells are still more favorable over vertical ones because they maximize reservoir contact and increase productivity index. In addition, horizontal wells yield higher drainage area and reduce water coning impact. Many horizontal drilling patterns have been evaluated in terms of distance between wells and the length of horizontal section heel to tail.

EHL (Effective Horizontal Length) has a great impact on EDA (Effective Drainage Area) of a horizontal well which can be used as indicator to evaluate the success of field development. Many data can be collected and extracted by remote real -time monitoring. These data can be used to estimate very important factors like reservoir permeability and drainage area at each foot of the horizontal section.

This paper presents a new approach of investigating EHL by using UBD (underbalanced drilling) data. Simulation studies were conducted through the horizontal section trajectory of the well to determine the reservoir drainage area along the length of the horizontal section. Eventually, the evaluated EDA summed up to produce the total productivity of the well using nodal analysis for each section separately. Results of this study showed very promising potential for actual field applications.
Improved Understanding of Static and Dynamic Geomechanical Stability and BHI Data Integration: Key for Improving the Completion of a Horizontal Well in Tiered Complex of Laminated Unconventional and Fractured Carbonate Reservoirs
Authors: Acharya Mihira N. , Kabir Mir R. , Al-Ajmi Saad A. , Pradhan San P. , Dashti Qasem M. , Al-Anzi Ealian H. , Chakravorty Sandeep
Published: November 2012

The deep, sub-salt reservoir complex is tiered with fractured tight carbonate at bottom and top, with the two sub-units of "upper unconventional kerogen" and "lower inter-bedded kerogen-carbonate" in the middle. This depositional setting is challenging for horizontal well placement where the thicknesses of respective sub-units are about 50 and 30 feet with varying geomechanical and petrophysical properties. Additionally, this complexity poses limitations in completions and effective stimulation of the Kimmeridgian-Oxfordian reservoirs in several gas fields at development stage in Kuwait.

A horizontal well is placed in the lower sub-unit of the laminated complex of unconventional kerogen and fractured carbonate reservoir as a Maximum Reservoir Contact (MRC) type well. A pilot mother-bore was drilled and logged to identify the lithological properties across the entire vertical domain - facilitates the optimization of horizontal drain-hole placement within the targeted reservoir units.

No wellbore stability issues in drilling were predicted based on the geomechanical understanding where core-calibrated logs from offset vertical wells were considered. However, this modeling method did not have the functionality to integrate the impact of drawdown on the laminated formation which became unstable and collapsed during the short open-hole drill-stem test (DST) plugging the tubing prior to the final completions. An alternative "book-shelf" geomechanical model was considered at pre-drill stage for predicting the wellbore stability. Once the drilling was completed, the time-lapsed multi-arm caliper indicated the validity of the alternative methodology in predicting the unstable stack of laminations in kerogen-rich strata.

The paper discusses an optimization methodology to enhance the understanding of static and dynamic geomechanical stability through the use of BHI data. Objective of the proposed method is to help improve the effectiveness of completions where wellbore stability due to geomechanical complexity in stacked-pay reservoirs is a primary wellbore challenge in deploying the completions and executing a subsequent stimulation and testing campaign.
Paper Title Asset Monitoring by Wireless Technology
Authors: Mukherjee Somen
Published: November 2012

No matter where an asset sits in the plant, the need to understand its health on a real time basis has become increasingly vital mainly because of growing need to focus on HSE commitments, intense global marketplace and high energy costs, safer and greener work environment. While most facilities continuously monitor their critical machinery and asset, their less-critical assets - often called "essential assets" - cannot typically justify the expense of a traditional continuous monitoring system due to the installation costs of running wires and sensors. Today there is a growing proliferation of wireless devices for many industrial and commercial applications - for security, safety, surveillance and machinery condition monitoring. Wireless technology innovations promise to open up a wide range of plant floor applications where cabling is either difficult to install or prohibitively expensive.
Some Thoughts of Acquisition Footprints Removal on 3D Seismic Data
Authors: Mahgoub Mohamed , Al Mesaabi Saif , Hagiwara Hiroshi , Matarid Tarek , Nakayama Shotaro
Published: November 2012

Acquisition footprint is a pattern on seismic data which is mainly caused by the sparseness of the acquisition geometry. It hinders seismic interpreters from accurate structure analysis by masking geological significances such as fault lineaments, channels and karsts. It is triggered by coherent changes in case of variable acquisition parameters and/or methods in the field, or alignments caused by the direction of data acquisition, and it is predominant on sparse acquisition geometries. Furthermore, it might be accentuated by multi-channels seismic processing such as stacking, DMO and pre-stack time migration if the aliased noise produced by the sparse geometry does creep into the seismic data.

In general, the acquisition footprint signature is rather strong in the shallow events due to relatively lower fold. Hence, it is strongly dependent on trace mute designs and sensitive to the amount of moveout and NMO stretch, where the influence is progressively healed with depth due to higher fold, wider mute parameters and smaller NMO shift.

It is known that remnant acquisition footprints often exist on the data after the application of the 3D F-Kx-Ky wave number notch filter. Although it may not always appear on the vertical cross-sections and time slices prominently after the attenuation, it might be pronounced on edge detection attributes, such as coherency cube, curvature and/or seismic impedance. There is some ongoing debate in Abu Dhabi between processing geophysicists and interpretation geophysicists as to whether apply harsh filter to clean up the residual footprint or to be more conservative while preserving some desirable subtle geological features as possible.

This paper advocates the necessity of time-variant 3D notch filtering approach regardless of the acquisition geometry and/or the area by showing some case histories from 3D seismic surveys offshore and onshore Abu Dhabi with three different acquisition geometries; orthogonal OBC patch layout, orthogonal land layout, and parallel OBC patch layout. Change of footprint characteristics in time, in association with adaptiveness of various notch filters in temporal/spatial domain, will b e discussed and demonstrated for each geometry type.
Well Log Conditioning for Quantitative Seismic Interpretation
Authors: Al Shekaili Fatema , Chacko Soman , El Din Samy Serag , Yin Yahui , Aurelie Pujol , Gael Lecante
Published: November 2012

Reliable sonic and density logs are needed for calibration of seismic data for use in reservoir characterization, and for specialized AVO and 4-D analysis. Due to the small depths of investigation of sonic and density logging tools, measured logs are affected by borehole washout and mud filtrate invasion. In many wells, particularly older ones, density and shear sonic logs were acquired within limited depth sections, or not at all. To address these various log quality issues and make the logs suitable for use with seismic data, appropriate log editing must be done, and missing logs or log sections must be synthesized. In addition, complex waveforms measured by modern sonic logging tools must be processed before they can be used for geophysical analysis, a step often ignored by geophysicists.

Our paper presents a sequential workflow to address sonic and density well log quality issues for approximately one hundred wells penetrating multiple carbonate reservoirs within a supergiant field from the Middle East. Borehole washout problems are frequent in the shales that overlie the main reservoir of the field, resulting in poor sonic and density log measurements. Within the reservoirs, high salinity filtrate invasion that displaces light oil affects both sonic and density log measurements. To address these issues, we developed a well log conditioning workflow that involves the following steps:

- Processing of sonic logs from wells with dipole sonic measurement - QC of all well data, and selection of wells with optimal logs for building a training data base - Generation of missing data using multi-variate statistical analysis - Correction of borehole-related anomalies - Correction for invasion effects - Validation against VSP and seismic data.

Results of log conditioning have improved well-seismic ties. In many cases these ties confirm the presence of residual interbed multiples within the 3D seismic data that covers the field. Modeling of fluid effects during invasion correction shows acoustic impedance to be sensitive to both porosity and fluid effects: up to 9% change occurs in acoustic impedance due to invasion-related saturation changes. Such saturation-related effects suggest the feasibility of 4D seismic as a surveillance tool in future FDP of the carbonate reservoirs in this field.
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

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

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

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

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

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

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

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

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

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

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

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

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.
Do Asphaltene Deposition Troubles Happen in Low Asphaltene Content of Crude Oil?
Authors: Takabayashi Katsumo , Maeda Haruo , Miyagawa Yoshihiro , Ikarashi Masayuki , Okabe Hiroshi , Takahashi Satoru , Al-Shehhi Hamad Rashed , Al-Hammadi Hamdan Mohamed
Published: November 2012

An extensive CO2 EOR study was done for one of a super giant oil field reservoir in offshore Abu Dhabi. This study aimed to evaluate the effectiveness of CO2 injection to the target reservoir and to address uncertainties based on laboratory and simulation studies. This paper is focused on the risk analysis of the asphaltene deposition in CO2 injection based on the laboratory data.

In this risk analysis, it is important to distinguish between asphaltene precipitation and deposition. It is believed that precipitation is a necessary but not a sufficient condition for deposition. In some cases, asphaltenes become unstable and form a separate asphaltene rich phase, but they do not deposit. Measurements of asphaltene particle size provide more understanding on the flocculation and deposition mechanisms and allow us to do the risk analysis of asphaltene deposition in CO2 injection. Pressurized oil samples were taken from the target oil reservoir. Laser Light Detection (LLD) and High Pressure Microscope (HPM) systems were utilized to measure asphaltene onset pressure and its aggregation process with injection of CO2. Asphaltene particle size analysis from HPM observations showed the growth of the asphaltene particles. Along with these analyses, CO2 injection core flooding tests were also conducted with this reservoir fluid and this reservoir rock. No symptoms of permeability reduction were observed through the experiments.

The overall conclusion of the study for the target reservoir revealed that the potential risk associated with asphaltene problems during CO2 gas injection was relatively low. In this study, 1) this laboratory study indicated the risk of asphaltene deposition by CO2 injection was relatively low in the target reservoir, 2) combination of the experiments revealed an asphaltene precipitation and deposition mechanism, and 3) this systematic approach was established to assess the asphaltene deposition risk.
Salt Tectonism Offshore U.A.E., a Studied Case
Authors: Al-Suwaidi Ahmad Saqer , Elsaid Mohamed Elhami , Ibrahim Khalil
Published: November 2012

The offshore of the United Arab Emirates (U.A.E.) contains a number of diapiric islands. These islands owe their relief to the diapiric movement of salt which has pierced and deformed the overlying strata. These islands have similar shapes, stratigraphic sequences, aerial distribution of the identified stratigraphic units and general tectonic framework as following: 1. Infracambrian to Cambrian (Hormuz Group) composed of igneous and metamorphic rocks, salt, anhydrite, carbonate and clastics interbeds. 2. Miocene that is composed of sandstone, siltstone, shale, carbonate and evaporite interbeds, and 3. Pliocene to Recent sediments composed of mixed facies of clastics, carbonates and evaporites.

One of the good examples is the pear-shaped Zirku Island with an approximately 5 km long and 2.5 km wide. A zone of very rugged hills with ridges is located in the centre and NNW with an elevated point of 163 meters.

Zirku Island was formed by the movement of Cambrian (Hormuz) salt that was deposited and had moved progressively upward, puncturing through the younger overlying strata to create a dome structure. The surface expressions are composed of evaporites rocks, plus igneous rocks and quartzitic sandstone.

The salt piercement is probably related to the Zagros Orogeny in the Pliocene to early Pleistocene and has brought in materials to the surface from considerable depths. On the Zirku Island the ‘exotic’ materials are represented by a rugged central region of lower Paleozoic contorted sandstones and siltstone of the Hormuz series. In the north east of the central core there is a sequence of steeply dipping lavas out-cropping the eastern flank of the ridge. Bordering the central zone is a gypsiferous breccia or mélange apparently formed around the margin of the Hormuz outcrop during emplacement from depth. The older Hormuz material has been eroded and partly incorporated into calcareous sediments formed along the shore of the ‘structural high’, probably in the late Tertiary period.
Full Field Development Plan Optimization Integrating Subsurface Reservoirs Uncertainties for Green Field Offshore Abu Dhabi, UAE
Authors: Afia Mohamed S. , Al Hossani Khalil , Matarid Tarek , Meziani Said , Al Badi Bader Saif
Published: November 2012

A green field offshore Abu Dhabi is planned to be developed with miscible crestal gas injection and peripheral water injection scheme. Close to 100 slanted and horizontal wells (single in dual/triple Reservoirs) will be drilled from 2 artificial islands targeting four Upper Jurassic carbonate Reservoirs. Risks appear in developing the field due to the uncertainties related to complex faults and fractures network, carbonate reservoirs heterogeneity, Tar Mat, sour fluid production, and high departure wells.

This paper illustrates full field development plan optimization studies that were conducted on a green field. The main objective of those studies was managing the reservoir uncertainties to enhance the full field development plans. 3D seismic, detailed sedimentological study, identified Reservoir rock types, Reservoir fluid characterization (Equations of state) and special core analysis (SCAL) using data collected from limited available wells were comprehensively evaluated and integrated to the input data of a 3D dynamic reservoir model.

In order to achieve the studies objectives, number of parameters were addressed and optimized during assess and select phases of the full field development plan. These parameters are miscible and/or immiscible Gas injection scheme, peripheral Water Injection, Gas Injection timing and balance (standalone field development), and well locations based on structural and sedimentological uncertainties.

Integration of static and dynamic data supported the development plan optimization to address the high uncertainty of the targeted Reservoirs. In addition, several sensitivity studies have been conducted for the reservoir uncertainty parameter ranges to understand their impact on the full field development plan.
Petrophysical Evaluation of a Gas Carbonates Reservoir through Integrated Workflow
Authors: Al Shehhi Noora , El-Hamawi Mohamed , Al Arfi Saif , Desport O. , Padiav P.
Published: November 2012

An appraisal well was drilled to assess the potential of gas bearing carbonate formations. The petrophysical objectives were to determine porosity, permeability, fluid type and saturation. The known presence of anhydrite and the lack of core information in the field to choose the Archie parameters were of concern for the evaluation and had to be addressed by the logging program and the interpretation workflow.

This paper illustrates how the challenge was addressed using neutron elemental spectroscopy to improve lithology and porosity computation, nuclear magnetic resonance and high resolution borehole image to compute a high vertical resolution permeability and finally dielectric measurement to refine Archie parameters.

This paper explains also how the core measurements and test results were used to validate the log measurements and interpretation workflow used.

This case study is a good example of addressing the well objectives using a properly designed logging acquisition and advanced interpretation workflow.
Using Frontline Data to Understand and Manage Cumulative Risk
Authors: Mackay Iain , Lehmann Scott
Published: November 2012

In any organization in hazardous industries there are three primary elements; the plant, the people and the interaction between the people and the plant. The interaction of the people on the plant represents millions of man hours per year for the typical organization and thousands of people every day who routinely intervene in plant operations to do repair and maintenance work. As a result, new hazards are introduced, safety systems are inhibited and parts of the plant are isolated, interfering with standard operating procedures.

The interaction of people with the plant is the biggest area of operational risk and uncertainty. It is the single biggest area of HiPO's, the second leading cause of fatalities and a major contributing factor in almost every process safety incident.

In order to reduce risk and optimize performance in this critical area we can use technology to provide operational assurance and predictive risk capabilities, ensuring people and plant interactions are fully captured into automated and embedded operational processes. Connecting policy to practice in this way ensures frontline workers are carrying out their work according to company standards while capturing and generating valuable data on the type, volume and interaction of work, as well as associated human factors. This provides common risk metrics across operations, enabling organisations to understand the relationship between delivering performance and managing risk.
Ichthys: From Challenge to Reality
Authors: Townsend William
Published: November 2012

INPEX has begun construction of one of the world's largest oil and gas projects following the Final Investment Decision (FID) on the US $34 Billion Ichthys LNG Project in Australia on 13 January 2012. The Ichthys LNG Project is a joint venture between INPEX (Operator) and Total with Tokyo Gas, Osaka Gas, Chubu Electric and Toho Gas.

The Ichthys Field is situated in the Timor Sea approximately 200 kilometers off the Western Australian coast and over 800 kilometers from Darwin. Three exploratory wells drilled in 2000 and 2001 resulted in the discovery of an extremely promising gas and condensate field with resource estimates from two reservoirs totaling approximately 12TCF of gas and 500 million barrels of condensate. Conceptual studies, FEED and ITT followed and development leading to sanctioning of the Ichthys LNG Project by INPEX and Total.

Gas from the Ichthys Gas-Condensate Field in the Browse Basin will undergo preliminary processing offshore to remove water and extract condensate. The gas will then be exported to onshore processing facilities in Darwin via an 889 kilometer subsea Gas Export Pipeline (GEP). Most condensate will be sent to a Floating Production Storage and Offloading (FPSO) vessel for stabilization and storage prior to being shipped to global markets. The Ichthys LNG Project is expected to produce 8.4 million tons of LNG and 1.6 million tons of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak.