bluuebunny/crossref_metadata_2025 huggingface dataset:
First Successful Hydraulic Fracturing in the Offshore Abu Dhabi: Part2—Overcoming the Operational Difficulties—
Authors: Al Ameri Fahed , Inukai Hisashi , Al Zarouni Asim , Al Kindi Mohammed , Kawamura Kazuhiro , Al Awadi Farhaad Khaled , Al Husseiny Afifi Hassan , Salman Mohamed Wajeeh , Moussa Khaled Abdel-Ghani
Published: December 2014

The first application of hydraulic fracturing in the offshore Abu Dhabi was executed safely and successfully. This achievement will be a valuable foothold to expand the field development target toward more challenging reservoirs such as deep tight sand in this region. There were huge amount of operational difficulties to carry out this hydraulic fracturing due to various operational restrictions, limited data availability and high-pressure & high-temperature (HP/HT) condition. Finally, these difficulties were successfully overcome by an intensive designing study on well completion, surface equipment, and operation associated with hydraulic fracturing for a tight gas reservoir.

In this paper (Part 2), the key factors that led this trial to the first successful hydraulic fracturing in the offshore Abu Dhabi are described against the difficulties from operational point of view such as well completion design, arrangement of fracturing and surface testing equipment and acquired lessons learnt. However hydraulic fracturing design optimization from subsurface point of view is discussed in the other paper described by Kuroda, et al. (2014) as Part 1. Well completion design and equipment arrangement were optimized to overcome an extremely wide range of pressure and temperature condition with multi stage fracturing. Fracturing and testing equipment of high specification were arranged on the limited space of both the off-shore jack up rig and the fracturing vessel, and then these well-prepared equipment contributed to safe and accurate operation. Acquired lessons learnt will contribute to other offshore tight-sand gas reservoirs development in the offshore Abu Dhabi. These outcomes will be especially applicable in this region to optimize offshore hydraulic fracturing for tight HP/HT reservoirs in order to enhance the well productivity and enable economical development of marginal fields.
Successful Integration of Innovative Technologies Enabled Operator to Drill and Complete First Horizontal Well in Depleted Shale Inter-bedded Limestone Reservoir in Pakistan - A Milestone Achieved.
Authors: Siddiqui F. I. , Naseem M. O. , Khan F. B. , Asrar M.
Published: December 2014

The name "Sui" has become synonymous with natural gas in Pakistan on discovery of the first well in 1952. Sui is Pakistan Petroleum Limited's (PPL) flagship gas field and is one of the major contributors in meeting the energy demands of the country since its inception. Two major reservoirs of this field are the Sui Main Limestone (SML) and Sui Upper Limestone (SUL); both of which have become highly depleted over time.

Pakistan is striving to meet its growing energy needs and is making all possible efforts to enhance production. Operator successfully drilled one horizontal well in the Sui Main Limestone in underbalanced conditions and planned to drill the FIRST HORIZONTAL WELL in the SUL reservoir to enhance production of the field. Drilling a horizontal well in this formation with conventional drilling techniques was a high risk task due to depleted reservoir with shale interbedding, complete loss of circulation, hole instability and reservoir damage issues which altogether made it almost impossible to complete the well.

The operator took this challenge to implement innovative technologies to mitigate all hazards and meet objectives. Drilling and reservoir related problems were identified in detail. A comprehensive Geo-Mechanics Study was conducted to define the safe drilling window of the SUL Reservoir. To maintain bottom hole pressure within the defined drilling window, further integration of Multiphase Fluid Drilling (Membrane Nitrogen & Water Based Mud) and Electromagnetic Measurement While Drilling tools along with real time ECD (Equivalent Circulating Density) and Gamma Ray monitoring Sensors were selected. A major challenge for the operator was to complete the well in the same reservoir conditions which was accomplished by applying Downhole Deployment Valve Technology with 9-5/8″ casing.

This paper will elaborate the details of planning and execution strategies to complete this challenging project. The application of these innovative technologies represents a step change in improving Operator's ability to exploit mature reservoirs, especially those that are severely depleted like the Sui Gas Field and also for the Oil & Gas Sector in Pakistan.
Simultaneous Operations for ADCO and Al Hosn at Shah Field
Authors: Kamran Ali , Kumar Chinculi Rajeev
Published: December 2014

Al Hosn Shah Gas (AHG) Development Project on-ground activities commenced in Shah Field during last quarter 2011.

Some of the major activities of AHG Project in Abu Dhabi Company for Onshore Oil Operations (ADCO)-controlled 40 km2 areas were: Initial demarcation and handover of the AHG well pads (eight locations)Movement of rigs, etc. to AHG well padsLaying of more than 50km length 16" & 20" diameter pipelines between the AHG pads and to the main Gas PlantProvision of Right of Way and berms for various pipelinesProvision of 11kv transmission linesConstruction of a new 25 km black top roadConstruction of Etihad Rail line, crossing ADCO Main Oil Line and Rig Route

Numerous ADCO live flow lines, 33kv and 11kv overhead transmission lines and underground network of communication and instrumentation cables were already present in these areas of AHG activities.

The mere safe handling of transporting men, machines and materials through all the above-mentioned live networks to various sites was an achievement in itself. It was a big challenge to protect and keep in service all the ADCO facilities throughout the AHG project. The main AHG project activities spanned a period of almost two and a half years.

A big logistical and social exercise of re-locating ADCO Shah and relevant service contractor personnel from ADCO Shah Camp was carried out in order to protect them from potential exposure to H2S and SO2 during flaring for AHG wells cleaning.

ADCO Shah Full Field Development (FFD) Project also took place in the same time frame. FFD was implemented in the locations where previous live facilities were already in operation. Apart from upgrading the Process Stations, instrumentation on most of existing wells was included in the FFD scope. The simultaneous supervision of these projects in brown fields is a testimony to the remarkable vigilance and hard work by ADCO Operation personnel.

This paper summarizes the ways and means through which the Simultaneous Operations (SIMOPS) management has resulted in a safe and smooth handling of all these activities, while outlining the plans for future parallel operations of the two OPCOs.
Cryogenic Tanks Re-Certification - Case Study
Authors: Adamou Adib Soufiane
Published: December 2014

Liquefied Natural - Petroleum Gas are usually stored by especially low temperature tanks, with different design configurations developed in the industry using steels with specified low temperature properties. This paper gives an overview on the properties, and behavior of the 9 %-Nickel-alloyed high strength steels for low temperature applications. These steels have been recognized by the ASME code for cryogenic use since 1954 and has been widely used for LNG storage in competition with stainless steel, other austenitic alloys and aluminum.in fact, austenitic stainless steels are used in cryogenic applications and can be used for building smaller storage tanks, but large containment vessels are usually welded from 9% nickel steel because of expense considerations. This technology is well-established worldwide. The first part of this paper is focused on the 9% nickel steel, its properties and, use in the LNG storage tanks.

The different LNG tanks design generations, their particularities will be described. A general overview of LNG tanks failures recorded in the industry will be presented as well.

Inspection, repair and alteration of atmospheric tanks designed according to API 650, are well covered with the API 653 standard, unlike the cryogenic tanks generally designed according to API 620 or BS 7777, no standard exists to cover the inspection, repair alteration requirements - when applicable - to recertify these tanks.

The document provides a benchmarking of different cryogenic tanks in terms of operation life and type of containment (single, double containment tanks) in the LNG industry. Different options are addressed in order to recertify these tanks are adopted in the industry will be detailed.

ADGAS operates three double walled tanks, reaching their design life. Longevity study was undertaken in order to re-certify the tanks based on different studies, inspection / operation / Maintenance history. Main outcomes of this study will be presented.
Data Acquisition and Appraisal Activity Challenges in Green Fields within a Remote Area - Case History from a Carbonate Reservoir
Authors: Akl Osama , Metwalli Magdy , Radwan El Sayed , Elbekshi Amer , Al Marzouqi Mohamed , Bin Kuwair Husam F.
Published: December 2014

This paper describes the frame work and new concepts implemented for appraisal data gathering from two undeveloped green oil fields (Fields-A and B) as shown in Figure-1. Acquired data program was a heavy schedule, involved testing of multiple wells, integrated by different teams to full fill all requirements which are vital for field's development. Limited resources, HSE and environmental issues, remote/unmanned areas, heavy testing facilities, rig & rig-less resources and difficult topographic nature of these areas are part but not all of the challenges faced to implement the appraisal data gathering program to achieve the program objectives. An integrated workforce team was formed from different disciplines, project partners and all stakeholders succeeded to set an innovative scope of work, plan, procedures and distribution of responsibilities for each partner to overcome and trouble shoot these problems. The appraisal data gathering approach resulted in completing the appraisal program successfully as per the time line plan, obtained high quality of huge data, adhering to high safety operating procedures and standards at economic value.

One of the major challenges was to avoid flaring of oil and risk of transporting huge quantities of crude oil produced during the long term production testing operation & risk of exporting by trucks to far locations at distances of around 130 Km from the source to store in other wells. Water handling during the injectivity test was also a big challenge. Safety operation related risk of high vapor pressure and flash point either in testing facilities or while loading and transportation in high temperature. H2S and SO2 are other issues. Proper planning, team work, risk assessment and mitigation plans, responsibility allocation the appraisal project was successfully completed in shorter time than expected and all objectives were met and obtained Shareholders gate approval to proceed with fields development in cost effective manner without any hazardous or fatalities.
Getting to Effective Solutions Instead of Blame - the Impact of the Human Factors and Classification System HFACS Approach
Authors: Cooke Steven J.
Published: December 2014

Effective corrective action has always depending on the correct and accurate identification of the real problem to be fixed. Investigation of system deficiencies and development of corrective action processes have evolved over the decades from "experience-based" expert teams (internal or external) to formalized methodologies than can be applied with a basis of training and moderate field experience. All formal Quality Management Systems (ISO-9001, ISO/TS 16949, AS 9100, Six Sigma) outline requirements for both correct investigation and documented corrective action. However, the best methodologies are not defined, leaving the success of these processes subject to significant variation. A plethora of Root Cause Analysis (RCA) methods are available, all based on the principles defined as early as 1905 in the Lancet article "The Present State of Medical Practice in the Rhondda Valley"1, and expanded in "Definition of a Root Cause" by Mark Paradies in October 20052. In the culmination of its development from 1985 in the development of the TapRoot® RCA method. As stated in the American Society for Quality (ASQ) book, "Some root cause analysis approaches are geared more toward identifying true root causes than others; some are more general problem-solving techniques, while others simply offer support for the core activity of root cause analysis."3

After years of experience with different levels and definitions of investigation procedures and corrective and preventive action (CAPA) activities, ADGAS recognized the need for a more objective and precise identification of systemic problems that were manifest in the continuing failure of individual action plans. A formal Root Cause Analysis (RCA) procedure and training were implemented to improve the investigation phase, but the systemic root causes remained elusive. Further research into behavioral safety led to the seminal work "The Human Factors

Analysis and Classification System–HFACS" by Scott A. Shappell of the FAA Civil Aeromedical Institute, February 2000.4 The HFACS was developed to address faults in highly-critical industries such as aerospace and military readiness, and has been adopted successfully by many other organizations. ADGAS has modified its Root Cause Analysis process to incorporate the HFACS at the "contributory cause" level. This change from the more simplistic assignment of "operator errors" has removed the assumption of blame to an improved understanding of the actions that can be taken by the company to prevent errors. The significance of the formal linkage from operator actions to corporate policies and structure cannot be overstated. A description of the HFACS and how it has been applied to improving asset Integrity and Reliability in ADGAS will be presented.
A Risk Based Approach for Prioritizing Electrical Equipment Replacement and Repair
Authors: Cayanan Christopher , Navarro Rey , Wagner Ernest
Published: December 2014

Electrical infrastructure equipment in the petrochemical and/or oil and gas industry in North America is generally 40 or more years old. The life and reliability of electrical equipment in this age range can be compromised due to operating conditions such as exposure to moisture and chemicals, loading, temperature, vibration, and mechanical stress over the life of the equipment.

Electrical equipment operating and life cycle philosophies tend to vary from age based replacement to run-to-failure. This results in an ad-hoc approach for determining the appropriate time for equipment replacements or major repairs. Limited resources, funding, and other competing projects exacerbate the issue.

An operating and life cycle management philosophy using preventive and predictive maintenance results to prioritize equipment replacements and/or improvement will help optimize how to determine when equipment repair or replacement is justified.

This paper will describe a systematic risk based approach of prioritizing electrical equipment replacement and repair projects to improve electrical reliability and safety. The approach uses probability and consequence techniques for equipment repair or replacement.
Maximising Enhanced Oil Recovery Opportunities in UKCS Through Collaboration
Authors: McCormack M. P. , Thomas J. M. , Mackie K.
Published: December 2014

The UK Continental Shelf (UKCS) is one of the most mature offshore basins in the world. Achieving optimal recovery from the basin is demanding, but as the anticipated ultimate recovery factor is 46% (1) of oil initially in place, there is still significant opportunity to optimise recovery from the existing oil fields. PILOT, a partnership between the UK Oil and Gas industry and the UK Government, has been re-focussing its efforts on maximising North Sea recovery.

There are currently only two Enhanced Oil Recovery (EOR) schemes operational within the UK North Sea. The principal barriers to implementing EOR projects are believed to be (1) incomplete subsurface understanding; (2) supply of secure, low cost injectants; (3) the challenge of implementing EOR retrospectively on a brownfield site; (4) concerns over project economics.

The PILOT EOR Work Group was set up in 2012 to co-ordinate industry and government attempts to tackle these challenges. A three phase programme was identified to: (1) systematically screen the UKCS fields for EOR potential; (2) engage industry and look for synergies and collaborative opportunities to progress EOR understanding; (3) where possible, initiate new EOR projects with operators.

The UKCS EOR screening exercise confirmed that there is still a significant realistically achievable EOR prize of up to 1 billion barrels of oil. The second phase of work focussed on developing collaborative ways of working to tackle the technical and commercial challenges associated with EOR projects, with particular focus on offshore ‘brownfield’ environments. Three EOR techniques were progressed and high graded on the basis of their prize and do-ability in an offshore environment: (a) Low Salinity Waterflood EOR; (b) Chemical EOR; (c) Miscible Gas Injection. Industry workshops were held for each EOR type and prioritised work programmes were implemented via operator "clusters", facilitated by the PILOT EOR Work Group. Examples of deliverables include (i) generation of a low salinity coreflood protocol to ensure that laboratory studies are performed in a consistent manner; (ii) initiation of a Joint Industry Project and an industry call for proposed facilities solutions for implementing low salinity on brownfield platforms; (iii) identification of industry resource to support UKCS operators with planning of chemical EOR opportunities. Successful completion of these collaborative activities will increase the chance of implementing further EOR schemes in the UKCS, unlocking the significant EOR prize.
Developments on Relative Permeability Computation in 3D Rock Images
Authors: Arrufat Tomas , Bondino Igor , Zaleski Stéphane , Lagrée Bertrand , Keskes Noomane
Published: December 2014

Digital Rock Physics (DRP) is commonly perceived as a range of technologies finalized at the calculation of properties of interest to geophysical, geological and reservoir engineering disciplines starting from 3D high resolution x-ray micro-CT images. Provided that verified, physically validated and controllable image acquisition and modeling workflows are available, petrophysical properties computed in this way can in theory be used in association to traditional difficult-to-obtain or often scarce core laboratory measurements to achieve higher insight of the reservoir and reduce the uncertainty in both static and dynamic models. DRP's potential for the industry is also expressed by the possibility of achieving better understanding of recovery mechanisms by probing fluid distributions at the pore scale, as is being nowadays investigated thanks to the utilization of miniaturized flow cells in micro-CT set ups or synchrotron facilities. This could be key for optimization of EOR processes.

From the point of view of operating companies, most efforts are still deployed in the R&D Lab with deployment of the technology in operational context still at its infancy and hindered by the issue of representativity of the microscopic imaged or computed scales (or image resolution-scale trade off), by the difficulty one has to unambiguously inform pore scale models with a sufficiently limited but precise set of physico/chemical information and by lack of robust validation procedures. In this dynamic and improving context, we update on our R&D efforts to evaluate and test one particular technology for the simulation of multi-phase flow in digital rocks, the Volume of Fluid method embedded in Paris simulator: the objective is to verify the potential interest in the medium and long term, knowing that other simulation technologies, being simpler to apply, are more mature for utilization in today's context. In this work Paris simulator is utilized to compute single and multi-phase flow properties on TOTAL's supercomputers for both a sandstone outcrop sample from Scotland and two carbonate rocks from UAE. First the simulator is tested for simpler permeability computations and benchmarked against a Lattice-Boltzmann solver; then the code is used for two-phase flow and for relative permeability computations. It is concluded that the particular simulator used in this work, still under development, can be used for different rock types and is particularly efficient in HPC environment: it has therefore strong potential. We conclude describing the future steps of development that will be needed to make the simulator applicable for digital petrophysics.
Assessment of Reliability of Cement Bond Evaluation with Some Interesting Field Case Studies
Authors: Ashena R. , Thonhauser G. , Dianati D.
Published: December 2014

High numbers of lack of hydraulic zonal isolation and occurrences of numerous high annulus pressure problems in wells in Middle East which has led to more remedial cementing and also workover rig days, has encouraged the industry to consider more efficient cement bond evaluation methods and discriminate between zonal isolation and cement bond log interpretation.

Therefore, in this paper the effects of the important parameters on cement bond logs including casing size, well deviation, type of fluid, and mud weight during the logging operations, surface applied pressure and microannulus, fast formations, type of formation, tool eccentricity, casing eccentricity, multiple casings, pressure and temperature, effect of cementing operations have been considered and the cement bond reliability has been discussed.

In this study, by presenting interesting examples of different cement bond logs, a comprehensive assessment of different cement bond log evaluation methods (conventional CBL/VDL, Radial CBL/VDL, Ultrasonic logs like segmented bond logs, isolation scanner in multiple casing scenario) have been performed which shows sonic cement bond logs are under some reliability risks and may not be always descriptive of zonal isolation. As ultrasonic tools outperform sonic ones, they are suggested specially wells with special cases.
Bravo Dome Subsurface and Surface Network Modeling
Authors: Nezhad Shahin , Williams Craig
Published: December 2014

Bravo Dome is a CO2 field in northeastern New Mexico State of USA which has been developed via more than 700 wells and approximately 600 miles of pipelines and flowlines. Nearly three-decades of CO2 production from the field have reduced the reservoir pressure from 350-400 psia to approximately 150 psia.

To explain wellhead pressures and the pressure drops along the pipelines which transfer the produced gas to the central plant, a combined subsurface and surface network model for evaluating the effects of reservoir, wells, flowlines, pipelines and compression plant performance and operational constraints has been developed to support further development and facilities modifications. The developed tool simulates CO2 movement all the way from the reservoir to the compressor station inlet.

The reservoir simulation model, built in VIP, was history matched based on reservoir and wellhead pressures. The surface network was built using Nexus. Historical and current operating conditions (wellheads pressure, node pressures and plant inlet pressure) were matched in the combined tool using pipeline and flow line roughness, WGR and "real" inside diameter of pipelines.

This approach identifies the potentials for improving the field performance of low-pressure gas fields. It encourages bottlenecks' identifications in complex surface networks and also brings ideas for facilities' modifications for enhance hydrocarbon recovery and field re-development.
Application of ‘Unified Fracture Design’ to Higher Permeability Reservoirs
Authors: Jangda Zaid Zaffar , Al-Nuaim Sami
Published: December 2014

Hydraulic Fracturing treatment design as classically used in the industry is based on the optimization of fracture geometry. However, the Unified Fracture Design (UFD) concept, allows hydraulic fracturing treatment design based on dimensionless fracture conductivity; with the best variable to characterize the size of fracture being the volume of proppant placed in the ‘pay’ rather than length and width, as the fracture geometry that would maximize production is unique for a particular mass or volume of proppant.

The purpose of this work was to design an effective and economical hydraulic fracturing job using UFD by selecting the amount of proppant that results in optimal treatment sizing, at which the Net Present Value (NPV) of incremental revenue balanced by treatment cost is maximum. This included selecting the appropriate proppant number which would give the best productivity index while the chosen proppant volume is placed according to the optimal dimensionless fracture conductivity.

Without going into the details of fracture mechanics, fluid rheology and reservoir engineering, the fracture treatment was designed by taking basic decisions in an iterative manner through an in-house developed program that can be used for any sort of reservoir. A real field case with medium permeability was chosen for optimization which resulted in a very high NPV value with the selected proppant design.

This work has great scope in designing hydraulic fracturing job using different kinds of proppants for different permeability formations, not restricting the applicability to low permeability formations.
Integrated Reservoir Management and Development Best Practice to Maximize Oil Recovery in a Mature Field
Authors: Al-Amrie Omar , Pearce Adrian , Gunasan Erkan , Madathil Asok
Published: December 2014

Oil demand is increasing globally while new oil developments are getting smaller and more challenging to develop (unconventional oil & gas reservoirs, deep offshore, tight reservoirs, heavy oil, acid gas, shale gas etc). In this context, extending the life of mature, conventional oil fields plays an important role in supporting world oil demand.

Reservoir management and development of these mature fields is challenging and requires innovative solutions given the increasing technical costs as production declines and asset/well integrity costs rise. Technically, a good understanding of reservoir behaviour and production mechanisms leads to implementing appropriate solutions to maximize field life, recovery factor and curb production decline. Commercially, the challenge is to find pragmatic and economically viable solutions.

The field discussed in this paper is a mature carbonate offshore oilfield in the territorial waters of Abu Dhabi operated since 1974. After 40 years of production, the field is still producing economically and currently is producing with an average water cut of more than 90%. This paper presents the continuous evolution of the technologies that have been deployed throughout the years to further valorise resources, in response to the growing maturity and complexity of the field.

Various IOR techniques have been employed in this field ranging from ESP's, gas lift, intelligent completions, multi-lateral wells, splitter wells, dumpflood to selective completions. In addition, various EOR techniques have been used ranging from full field tertiary hydrocarbon gas injection to chemical and enzyme EOR pilots.

Given the aging production facilities, field management is a daily challenge. The complex gas scheme composed of simultaneous gas production, tertiary gas injection, gas lift, gas recompression and gas export requires continuous arbitration between activation gain and tertiary recovery.

Lessons learnt, good and bad, will help maximize future recovery in other less mature fields in the UAE.
New Generation Ultra-High Temperature Synthetic-Based Drilling Fluid; Development and Best Practices for Extreme Conditions and ECD Management
Authors: Marinescu Pavel , Young Steve , Iskander Gamal Ramses
Published: December 2014

In the last years the quest for hydrocarbons findings moved into extreme drilling condition, such as ultra-deep waters, ultra-high temperatures and drilling fluids densities. Adding to these the very narrow density windows (reservoirs with very low differential fracture pressure - pore pressure), both operators and drilling fluids service companies faces increased challenges to deliver the well for production. It is common that for such applications the bottom-hole static temperature is over 180°C/356°F, even reaching temperatures in excess of 250°C/482°F in some fields, acid gases (CO2, H2S) are also present, so the list of challenges is formidable.

In this paper, the authors details the common challenges for such extreme conditions wells and best practices, present a new generation synthetic-based fluid capable to withstand temperatures in excess of 500°F/260°C, as well as a unique hydraulics engineering calculations software which enable real time equivalent-circulation density (ECD) calculations.

The design and development of the mew ultra-high temperature mud system is presented and its components. At the core of the system it is a new amine-free emulsifier, which is stable to temperature above 300°C/572°F. In addition, the authors will present the extensive lab work required to optimize the formulation for high densities and extreme high temperatures, detailing also the critical fluids engineering guidelines for drilling in such harsh conditions.

Using laboratory, field, and computer data, the authors will demonstrate the effectiveness of the new fluid in delivering optimum drilling in extreme HTHP conditions. Also, it is illustrated how the rheology is maintained at minimum level with a micron-size weighting material, and the engineering software used for pre-planning and while drilling to accurately calculate the ECD and maintain it within the required range.
Dewatering Pigging Frequency For Oil & Gas Pipelines Modified Approach
Authors: Grandhe Siva Prasadarao , El Alfy Mahmoud
Published: December 2014

ADCO operates ~165 nos of piggable Oil & Gas pipelines extending over 2500KM. These pipelines transport produced Oil & Gas fluids from RDS, RMS`s to CDS at each interior based Assets and later the treated Oil & Gas is transported to export, distribution terminals with in UAE. The age of these pipelines is in the range 2 to 50 yrs.

The dewatering pigging activity is performed on critical piggable Oil & Gas pipelines at specified regular intervals towards removing the stagnant corrosive water, debris from the bottom of the pipelines, thereby improving the performance of internal corrosion management systems. With the aging of reservoirs associated with implementation of enhanced oil recovery techniques such as water injection, Gas injection etc., the BS&W levels & GOR levels are increasing day by day with the produced crude oil. This has led to high fluid velocity in many operating oil transfer lines.

There is no industry standard and or code of practice available for deciding the de-watering pigging frequency for the pipelines. In view of risks associated with pipeline pigging activities, production deferments associated with pipeline pigging activity with the high flow rate pipelines and the requirement for enhancing the efficiency of internal corrosion mitigation systems, an optimized structured semi-quantitative risk based approach is developed for identifying the optimal pigging frequency for piggable Oil & Gas pipelines based on pipeline throughput, integrity status & operating conditions.
Water Saturation Modeling of Complex Carbonate Reservoir: A Case Study of Challenging Highly Impacted Reservoir by Diagenesis Processes
Authors: Voleti D. K. , Al Mazrouei S. , Al Nuaimi L. Obaid
Published: December 2014

Modeling of water saturation in carbonate reservoirs is a challenging task which becomes more difficult if the reservoir is highly affected by diagenesis processes. This paper addresses a robust water saturation modeling workflow that encompass multiple approaches followed to handle an onshore Abu Dhabi carbonate reservoir that have complex pore network. This covers a holistic reservoir petrophysical evaluation all the way to water saturation modeling for dynamic simulation studies.

The studied reservoir was deposited in high energy shallow, water platform environment prevailing during Early Cretaceous time. It has a large areal extent with low average porosity and moderate to low average permeability.

Considering the impact of porosity exponent (m) and water resistivity (Rw) on the water saturation evaluation, the workflow was adjusted to integrate all available log, core and well test data. By integrating the formation resistivity factor (FRF) at different net confining stress and petrography data, relationship for variable porosity exponent (m) versus porosity was developed.

The salinity variation was observed across the field (east to west) from the well test and Pickett plot. In water saturation estimation, salinity taken from one side of the field (east/west) causes either under or overestimation of water saturation by 18% on the other side of the field which has a Considerable impact on the STOIIP. To address this problem, variable formation water resistivity (Rw) was generated from log data. This was validated using Porous Plate capillary pressure data measured using samples collected from different areas of the field.

The destructive dolomitization at the bottom part of the reservoir resulted in the large transition zone and sporadic occurrence of poor lithofacies poses a great challenge in developing a saturation height function. The current case study also evaluates the best possible saturation height function which can explain the variability of water saturation across the field.
Quantifying HSE Culture – A Leading Indicator of HSE Performance: An Energy Industry Case Study
Authors: Rodrigues C. C. , Simmons R. J. , Atanas J. P.
Published: December 2014

This paper presents the results of an HSE Culture survey administered to employees and managers at an energy company. HSE culture can be defined as the value and priority placed upon HSE by every individual in an organization, and can be seen as the shared values and norms of personnel within a company, their perceptions, feelings, beliefs, and attitudes about the HSE risk to which they are exposed, and their beliefs regarding the necessity and success of HSE control systems. The HSE perception survey is a commonly-used technique for assessing HSE culture. HSE perception surveys provide leading-indicator information on safety performance and can identify areas and activities with the potential to undermine HSE performance. Furthermore, perception surveys can measure effectiveness of HSE systems as described by individuals within an organization, reveal strengths and weaknesses in current systems, and can identify what needs to be done to correct identified deficiencies. The aim of this study was to evaluate HSE culture within the selected company using a technique that is well-documented in the literature. An 8-parameter, 5-element per parameter, Likert scale survey instrument was developed and administered to 108 employees and managers at an energy company. The collected responses were analyzed using Minitab. The results showed that, overall, the company's HSE culture was rated as positive by both employees and managers. In addition, further study of individual parameter groupings revealed that system safety and risk management made the greatest contribution to the positive HSE culture for the company. This was interesting, as it suggests that the average employee has a sense that engineers can play an important role in affecting the overall HSE culture of a company, as they are the usual implementers of system/process safety in the company. This has implications for the importance of creating an HSE-Through-Design culture within the engineering organization at a company.
A New Method of Surface Wave Analysis and OBC Signal Enhancement in Shallow Water Environment of the Arabian Gulf using Time-Frequency-Wavenumber Polarization Analysis
Authors: Zhang Zhao , Sun Yuefeng , Berteussen Karl , Ali Mohammed
Published: December 2014

In the shallow water environment of the Arabian Gulf, a combination of strong lateral seafloor heterogeneities, shallow water depths (~10m), and hard sea bottom results in highly dispersive and aliased surface waves with complex wave-field polarization in all four components of the OBC seismic data. Compared to body waves, surface waves are characterized by low velocity, low frequency and high polarization and their polarization states are time, frequency and mode dependent. Those properties challenge the existing surface waves filtering techniques because they take into account velocity, frequency or polarization only. Consequently, the residual surface wave leads to inaccurate directional analysis and has severe adverse effect on the quality of subsequent seismic data processing algorithms.

Considering the joint relationship among wavenumber, time, frequency and polarization of surface waves, we propose a two- step rotation method to separate the surface waves from the reflected waves and estimate wave polarizations. First, we use a non-stationary FK filter to eliminate the effect of the surface wave from OBC record in the time- frequency-wavenumber (TFK) domain, where we can define the surface wave rejection zone by its low frequency, low velocity and high amplitude characteristics. Second, considering the pattern of particle motion and propagation directions, we estimate wave-field polarization features by extending the traditional single domain polarization analysis into the decomposed TFK domain. Spherically polarization noises (surface waves) can be distinguished from rectilinearly polarized waves (body waves) through covariance matrix calculation for each TFK point. Therefore, the residual surface wave which overlaps with body waves in TFK domain are eliminated based on its polarization characteristic. Analysis on field data shows that this proposed new method is effective in both attenuating the surface waves and providing reliable information on orientation, which are critical for the further processing on the shear wave and converted wave in horizontal components.
Destruction of H2S Contaminants (Benzene, Toluene and Xylenes) by Sulphur Dioxide in Claus Process
Authors: Sinha S. , Raj A.
Published: December 2014

Claus process, consisting of a furnace and catalytic reactors, is used to recover sulfur from H2S found in raw natural gas and gases from refineries. This acid gas is accompanied by contaminants such as benzene, toluene, xylenes (collectively called BTX), other hydrocarbons, NH3, CO2, N2 and sulfur compounds having detrimental effect on catalytic reactors, where BTX form soot particles and sulfur-hydrocarbons, and clog and deactivate the catalysts. This work focuses on BTX oxidation by SO2 as a potential solution that can be carried out in a BTX destruction unit placed between Claus furnace and catalytic units. Density functional theory is used to study the interaction between BTX-radicals and SO2 and the stability of the intermediate species formed during the course of the mechanism. The rates of elementary reactions are evaluated using transition state theory. The pathways leading to the formation of important by-products such as CO, SO, S, CHO were obtained.
Enhanced Gas Recovery by CO2 Sequestration versus Re-fracturing Treatment in Unconventional Shale Gas Reservoirs
Authors: Eshkalak Mohammad O. , Al-Shalabi Emad W. , Sanaei Alireza , Aybar Umut , Sepehrnoori Kamy
Published: December 2014

It is proposed that very low permeability formations are possible candidates for CO2 sequestration. Further, experimental studies have shown that shale formations have huge affinity to adsorb CO2, the order of 5 to 1 compared to the methane. Therefore, potential sequestration of CO2 in shale formations leading to enhanced gas recovery (EGR) will be a promising while challenging target for the oil and gas industry. On the other side, hydraulic re-fracturing treatment of shale gas wells is currently gaining more attention due to the poor performance of shale gas reservoirs after a couple years of production. Hence, investigating and comparing the performance of CO2-EGR with the re-fracturing treatment is essential for the future economic viability of depleted shale gas reservoirs. This paper presents a systematic comparison of the effect of these two processes on improving gas production performance of unconventional reservoirs, which is not well understood and has not been studied thoroughly in the literature.

In this paper, a shale gas field data has been evaluated and incorporated in our simulations for both CO2-EGR and re-fracturing treatment purposes. Numerical simulations are performed using local grid refinement (LGR) in order to accurately model the non-linear pressure drop. Also, a dual-porosity/dual-permeability model is incorporated in the reservoir simulation model. Further, the uncertainties associated with inter-related set of geologic and engineering parameters are evaluated and quantified for re-fracturing treatment through several simulation runs. This comprehensive sensitivity study helps in understanding the key reservoir and fracture properties that affect the production performance and enhanced gas recovery in shale gas reservoirs.

The results showed that re-fracturing treatment outperforms CO2-EGR due to the pronounced effect on cumulative methane gas production. Moreover, the sensitivity analysis showed that the characteristics of reservoir matrix including permeability and porosity are the most influential parameters for re-fracturing treatment. The findings of this study recommend hydraulic re-fracturing of shale reservoirs at first for enhancing gas production followed by CO2 injection at a later time. This work provides field operators with more insight into maximizing gas recovery from unconventional shale gas reservoirs using re-fracturing stimulation, CO2 injection, or a combination of both methods.
Green Hats Induction Program Ensures Safer Workplace
Authors: Ahmed Y. E. , Stander A. , Al Mansouri E. , Turki S. A.
Published: December 2014

Like most drilling contractors worldwide, till a few years ago new recruits joining the company were given a quick induction of few hours in the head office and then dispatched directly to the assigned rigs. Thereafter, rig staff spent time and efforts to train them and get them familiar with company systems. In 2006, the company's management established a specially tailored six week Green Hats Induction Program to get all new recruits familiarized with company rules, regulations, basic safety and drilling procedures - the term "Green Hat" being used to denote employees new to the company who must wear green hats to distinguish them on rigs and require mentoring till they are fully familiar with the assigned rigs The program that was commenced using HSE certified instructors involved discussions between company and OPCOs managements to discuss and review the program syllabus, in addition to the involvement of concerned divisions within the company.

Initially started for junior recruits, within one year, this was expanded to include senior recruits due to the successful outcomes and staff awareness of the first batches.

The Green Hats induction program adds value to the core business of National Drilling Company. It enrolls fresh hires - both new and mid-career hires - and introduces them to the life cycle of wells (drilling and work over) with emphasis on Rig HSE, Drilling Operation and Equipment, team building for onshore and offshore units. All employees undergo mandatory certified courses to allow them to proceed directly after the training to their selected units and to get them familiarized with NDC operating systems and procedures, thereby ensuring personnel safety and a hazard-free work environment in NDC operating zones. By 2009, the Green Hat Program was accredited with the IADC (International Association of Drilling Contractor) Rig Pass – a huge achievement for the company.

Since 2006 a total of 2890 employees have benefited from the Green Hat Program, clocking over 59000 training mandays. The greatest benefit of this program has been the safer workplace and accident mitigation.

This paper shares with the industry the success story and the evolution of this program from its humble beginning to its present success.
Managing Talent Data for Decision Making: Developing ADCO's Succession Management System
Authors: Al Muhairi Ayesha O. , Montes Juan
Published: December 2014

As every organization grows they need to ensure that processes are in place to attract, retain and develop their talent. Succession Planning and Management is a strategic process that focuses on creating a sustainable value chain of high potential talent who have the requisite knowledge and skills to lead and manage new organizational requirements and address business challenges. To manage this process they need to adapt a range of methodologies to select, measure and distinguish between those who are truly high performers with potential.

Abu Dhabi Company for Onshore Oil Operations has implemented the succession planning system from way back in 2006 in preparation for significant challenges in the horizon for which the organization needed to be prepared for:. The challenges included:

Growth in production targets from 1.4 Mbpd to 1.8 Mbpd by 2017 Maturing and more complex fields The need for new technology to be installed to enhance recovery and oil extraction The emerging crew change brought forth by aging manpower and experience dilution and the steep learning curve for newcomers. Reaching the Emiratization target (75%) by 2017,

Implementing a succession plan process within the company was seen as one of the significant intitiatives to support the development of technical capabilities and leadership capacity to address these challenges.
Successful Coring in 8.5-in. Hole Section using Anti-jamming Technology in Southern Iraq
Authors: Khan Asif M. , Onezime Jerome , Mosalem Diaa , Amos Trost , Pointing Mike , Vyas Vishal
Published: December 2014

Field data presented in this paper demonstrate how anti-jamming coring technology was used to improve coring operations at Majnoon field. Majnoon field is located in the southern part of Iraq and is still early in its development phase, with many geological uncertainties. In this geological environment, core samples from the reservoir sections are essential for geologists, geophysicists, and reservoir engineers to better understand and develop a detailed reservoir model.

Previous attempts to obtain core samples in this field experienced poor efficiency, with recurring jamming and limited core recovery, resulting in additional rig time. The lithology of the cored interval consists of interbedded sand, shale, and limestone having occasional traces of pyrite, which has a tendency to damage core bit polycrystalline diamond compact (PDC) cutters.

To overcome these issues, anti-jamming technology featuring a spring loaded-spacer and double-bearing inner assembly was used to core through two compact formations of the well. This technology has already proven its value in other parts of the world; however, this was the first time it was implemented in southern Iraq, achieving its objectives and saving rig time. Seven separate runs were made to cut 151 m of core, all resulting in 100% core recovery at surface with excellent efficiency (98%).

This paper discusses the application of the new coring technology coupled with a premium cutter core head and optimized bottomhole assembly (BHA), which helped mitigate the risks associated with the previous runs and cored into an 8.5-in. section without experiencing any problems.