bluuebunny/crossref_metadata_2025 huggingface dataset:
Baseline Establishment for a Polymer Flood Pilot Test in an Unconsolidated Sandstone Reservoir in the South of the Sultanate of Oman
Authors: Al-Sulaimani Hanaa , Al-Rawahi Zainab , Quesada Conny Velazco , Al-Ghannami Mohammed , Frumau Mervin , Al-Hussaini Azza , Hemink Gijs , Nadeem Muhammed , Khattak Ali , Al-Hinai Ghalib , Al-Mahrooqi Majid , Al-Shidi Maitham , Syed Muhammad
Published: November 2017

Petroleum Development Oman (PDO) has commenced several Enhanced Oil Recovery (EOR) methods in the Sultanate of Oman to increase recovery from fields with challenging rock and fluid properties. Polymer flood is one of the mature EOR techniques that are currently operated in sandstone reservoirs in the South of Oman.

The reservoir under trial in this paper shares its OWC with another reservoir that has been developed through polymer flood. Although they both share similar fluids with viscosity of ~90cP, the reservoir under trial exhibits significant lower permeabilities, which poses a risk to injectivity. Furthermore, well completions with sand control have shown to be too detrimental to productivity which causes high sand production. This creates a challenge for the polymer flood from both the injectivity and sand control point of view. Thus, a pilot was designed with the following three objectives; test ability to sustain injectivity of polymer into the reservoir, monitor polymer efficiency, and evaluate operational impact on facilities due to sand production that is expected to increase with polymer flood.

The pilot was designed such that two patterns are drilled adjacent to each other where one will be used for the polymer flood and the other pattern serves as a backup in case the first pattern suffers from loss of injectivity or any unforeseen issues. The patterns are inverted five spots with an injector-producer spacing of 75m. The injectors are equipped with fiber optics for data acquisition and real time temperature and acoustic surveillance. The plan is to inject water until a baseline is established, which is then followed by polymer injection for up to one year.

Currently, the project is in the water injection phase where information and data are gathered such as injectivity, conformance, reservoir connectivity in addition to fluids production baseline establishment. This paper presents those findings from the water injection phase in addition to design aspects for the polymer phase.
Tackling the Problem of Ageing Well's Integrity and Rehabilitation in the Arabian Gulf
Authors: Ramasamy Ramesh , Chau Eric , Ibrahim Zainah
Published: November 2017

The Arabian Gulf and the surrounding GCC regions have some of the world's oldest oil and gas fields dating back to the 1930s and 1940s, some of which are still actively producing. From a design perspective, the oil wells in these fields have operated beyond their design lives. However, due to the recent decline in oil prices, there is an ever increasing demand to keep these assets producing for the foreseeable future. It is therefore critical that the asset owners/operators develop a thorough understanding in the health conditions of these aged wells and also to put in place an effective well integrity management system to ensure the longevity of these assets. This paper presents a novel approach towards well integrity management utilising advanced modelling of the well structure coupled with a newly developed non-destructive examination technique to provide the best possible assessment of the health condition of the well system.

An accurate assessment is paramount for operators and assets owners in understanding the health of aged wells in order to continue operate in a safe manner. Traditionally, health assessments are being carried out using original design data and acceptance criteria derived from internationally recognised codes and standards. Whilst providing useful estimation of the condition of these aged wells, these assessments failed to address the actual loading conditions in the well casings. Instead, considerable levels of conservatism/ safety factors are being used, leading to needless underestimation of remaining lives and hence premature remedial works are potentially being carried out at great costs.

A rationalised assessment approach is described herein whereby a set of customised acceptance criteria are being developed based on design data, geotechnical and environmental data, operating history and outcomes from inspection activities. A combination of specialist inspection and re-assessment strategy have also been developed to determine the residual loads within conductor/casings and the corresponding stresses to accurately pin-point current integrity state of these conductors and casings.

The preliminary assessments carried out provides a great insight into the condition of these aged wells, but at a cost of being over-conservative. The criticality prioritisation curves are developed to identify the particular oil well which is being assessed within a certain risk category. The recent development of the specialised inspection tools and methods have reduced these over-conservatisms and thus eliminated the need for premature repairs on effective wells. The entire screening process to identify critical aged wells have also been automated in a computer based scripting for rapid, robust and repeatable use by facility and integrity engineers undertaking overall screening of large number of wells over aged fields.
Digitally Enabled Top Drive
Authors: Holm Anders H.
Published: November 2017

The top drive is designed to provide the highest level of instrumentation to ensure that the operator get total control of the drilling process.

High accuracy sensors and actuators increase drilling efficiency due to better drilling data insight and the ability to respond quickly in a demanding drilling environment that ensures safer drilling operations for the rig crew.

The top drive is suspended from the travelling block using 4 vertical tie rods with an innovative weight on bit (WOB) system. Redundant built-In WOB sensors in all the tie rods provide exceptionally accurate load readings over the entire top drive hoisting range. Accurate WOB measurements is important for the driller to be able to apply the correct downward force needed for the bit to efficiently break rock as well as extend bit lifespan. The top drive’s accurate WOB system decrease the number of time consuming bit runs as the lifespan of each bit is prolonged.

Soft cushioning while doing spin in / spin out pipe connections are controlled using an active tread compensating system in hydraulic cylinders suspended between the travelling block and top drive gearbox. Stroke sensors provide the driller with additional control over actuators and top drive movement which in turn improve operational efficiency and rig safety.

The top drive is powered by two high performance AC motors delivering one of the highest levels of torque and speed. The two 550 HP motors provide 51 000 ft-lb of continuous torque enabling deeper drilling both vertical and horizontal. The motor configuration is designed to be redundant allowing continuous operation at 100% speed and 50% torque if one motor is offline. The redundant individual driven traction AC-motors are crucial to ensure reliability and rig uptime.
Directional Underbalanced Drilling Success With Up to 40% Nitrogen Using Mud-Pulse MWD and Rotary Steerable Technology
Authors: Dolman Lee , Sudron Ken
Published: November 2017

This paper describes the successful use of mud-pulse Measurement While Drilling (MWD) and Rotary Steerable directional systems (RSS) in an Underbalanced Drilling (UBD) environment utilising up to 40% nitrogen. There are few documented examples of mud-pulse telemetry being successful above 20% gas/nitrogen, and fewer with RSS directional drilling technology. It will be shown that reliable mud-pulse telemetry is now achievable at previously undocumented levels of gas injection that has re-defined the operating envelope for two-phase drilling fluid operations with conventional mud-pulse MWD and advanced RSS directional drilling services and technology.
Evolution of Coiled Tubing Fiber Optic Real-Time Telemetry System in Saudi Arabia Ghawar Field Interventions
Authors: Al-Duaij Ahmad N. , Al-Buali Muhammed H. , Ahmed Danish , Arifin Mohammad , Ayob Adzlan , Sa Rodrigo , Pochetnny Valentin
Published: November 2017

This paper will discuss the coiled tubing (CT) fiber optic real-time telemetry system evolution for varied interventions performed in Saudi Arabia’s Ghawar field. The paper will show the benefits achieved with consistent improvement of the CT fiber optic real-time telemetry system, leading to better understanding of intervention and reservoir in real-time, optimization of treatment, opening new horizons and meeting huge successes.

For years CT with fiber optic real-time telemetry, has been used in Saudi Arabia Ghawar field, whereas the initial version of the CT fiber optic real-time telemetry system consisted of 2-1/8 in BHA, comprising measurements of pressure, temperature, casing collar locator, gamma ray, tension and compression and distributed temperature sensing. Though the successes achieved from this system were remarkable, it was restricted to 2-bpm, had temperature limitations, and was not able to bear shocks and vibrations. As the time passed, interventions became more challenging. In order to meet well intervention objectives, a new tool was developed enabling higher pumping rates up to 8-bpm, and working temperatures of 300 °F. The challenge of bearing high shocks and vibrations was still not met, so a new was further designed to meet that objective. In the field, the new tool proved to be the most superior and advanced one, as the CT fiber optic real-time telemetry system gave high pump rates of 8-bpm, worked at temperatures of 350 °F, has a higher pressure rating, and was used in interventions where high shocks and vibrations were encountered. In addition to the above-mentioned CT fiber optic real-time telemetry system evolution, the system was enable to run the logging tools, leading to the development of a CT dedicated downhole flow measurement tool.

These new tools provided the following advantages: optimize the treatment stages during a particular intervention, help operators gain a better understanding of the well and reservoir response during an intervention, assist in optimization of treatment strategy, and enable pre and post-treatment evaluation in minimum CT runs.

This paper will explain the evolution of the CT fiber optic real-time telemetry system, and the significant impact the system has made to the oil and gas industry. The system enables CT interventions in a concise manner where decisions during a treatment are made using both surface and downhole parameters.
Feasibility of Foam Application in a Giant Mature Field Under Miscible WAG Injection
Authors: Bascialla Guido , Montes Jesús , Romero Pedro , Rodriguez Rosario , Del Moral Jaime
Published: November 2017

A giant mature light oil field under miscible WAG injection is a potential candidate for foam application to control gas mobility and reduce field gas – oil ratio (GOR). We conducted a feasibility study which comprised live oil corefloods at reservoir conditions and compositional numerical simulation coupled with a foam formulation. The objectives of this study were to identify critical variables and potential detrimental factors for the process implementation; and evaluate the GOR decrease due to foam application.

This feasibility study comprises an evaluation of the effect of foam on a field scale through numerical simulation, and the study of foam creation under reservoir conditions through coreflood experiments. We used a compositional simulator with an empirical foam implementation to predict the effect of foam in a mechanistic sector model of a high production area of the field. Simulation results show that foam is able to reduce field GOR by reducing the mobility of injected gas in high permeability layers. It became clear that the incremental oil production is strongly dependent on gas production limits; thus, foam application has to be coupled with overall field optimization.

Due to challenging field conditions for foam application, we performed an extended laboratory study. Static mixing experiments allowed surfactant compatibility limits in mixtures of formation and injection brines to be defined. In addition, a series of corefloods showed that foam can be successfully generated with a commercial alpha-olefin-sulfonate surfactant under reservoir pressure and temperature in presence of live reservoir oil, rich hydrocarbon gas and injection brine.

To our knowledge this is the first published feasibility study of foam application in a mature miscible WAG project including compositional simulation and live oil corefloods with rich hydrocarbon gas injection under reservoir conditions.
Base-Line Logging Before Commencement of the EOR Project to Enhance the Chances for Success
Authors: Al-Qenaie A. , Chetri H. B. , Tiwari S. , Al-Twaitan T. M. , AlAbdullah M. B. , Ranjan P. , Aslanyan I. , Prosvirkin S.
Published: November 2017

Successful EOR project management in mature fields depends on proactive planning that includes reservoir characterization and determination of the engineering design parameters. Base-Line logging performed in the pilot EOR pattern before implementation of an EOR project will make possible an early detection of any potential problems and weaknesses to avoid costly subsequent repairs or alterations. The objective of this paper is to demonstrate the results and value of Reservoir-Oriented Base-Line Logging carried out in Sabriyah Field, Kuwait, before ASP injection. The Base-Line logging is focused on the flows behind pipe and any anomalies that might have impact on the project.

Seven new vertical wells were drilled in a selected area within an existing waterflood pattern, to monitor the viability of pilot polymer injection in the field. An integrated suite consisting of reservoir evaluation tools, High Precision Temperature (HPT) and Spectral Noise Logging (SNL) tools, and metal losses evaluation tool (EmPulse), were run on slickline under shut-in conditions. Temperature is sensitive to any lateral flows and possible behind-casing cross-flows between permeable zones. Spectral noise logging can distinguish between noises caused by fluid flows through well completion elements and the reservoir. The idea was to record the wellbore and reservoir initial conditions before any mechanical or reservoir effects begin to influence the EOR performance. Analysis of subsequent Time-Lapse logging would be easier with this base-line information on hand.

The five wells were drilled in a 5-spot pattern in the selected area, with two additional logging well and a sampling well for continuous monitoring. The objective was to check for possible communication of the target reservoir with underlying and overlying formations to prevent off-target chemicals injection, and get a baseline for metal thickness of each barrier. At the same time, it was vitally important to trace the cold injection water propagation in the target reservoir before the EOR started.
Experimental Investigation of the Effects of Rotational Speed and Weight on Bit on Drillstring Vibrations, Torque and Rate of Penetration
Authors: Bavadiya Vimlesh A. , Alsaihati Zeeneb , Ahmed Ramadan , Gustafson Kyle
Published: November 2017

Drillstring vibrations namely axial, lateral and torsional vibrations are the primary reason for downhole tool failure and reduction in rate of penetration (ROP). Factors like bit design, bottom hole assembly, bit-rock interaction, rotational speed, wellbore hydraulics, weight on bit (WOB) and drillstring-borehole interaction affect vibrations, out of which only rotational speed and WOB can be changed in real-time to minimize vibrations. It has been a topic of interest to understand and model downhole vibrations, minimize them and find an optimum range of drilling parameters to increase the drilling efficiency.

This article presents the results of experimental studies conducted on a fully automated drilling rig to examine the effects of drilling parameters on drillstring vibrations, torque and rate of penetration. The study is different in terms of the high-speed range and the use of axial vibration transmitter to measure the vibration severity as per ISO standards. Experiments were performed on two different rock samples with varying strength. Perfect hole cleaning with negligible fluid flow effect was assumed. Each experiment was run for an average of six minutes collecting an average of 120 data points which were then averaged out for analysis. Parametric study was carried out to analyze the impacts of bit strength to rock strength ratio, bit constant and intrinsic specific energy on torque using existing model. As the drillstring was stiff and small, torsional oscillations were not observed and only lateral and axial vibrations were studied. Effect of drilling parameters and vibration on ROP was studied only on soft rock sample as ROP on hard rock was too small to be recorded

Once the input parameters for the analytic model were methodically selected they show good agreement with the experimental data. The results of the parametric study revealed that estimation of torque relies heavily on the bit constant. Axial vibrations increased when rotational speed was near to the natural frequency of the drillstring which resulted in increase of ROP. Type of formation affected the magnitude of lateral and axial vibrations. Reducing both rotational speed and WOB helps to minimize lateral vibrations in hard formations while reducing rotational speed can effectively reduce axial vibrations.
Step Change in Deepwater Drilling Performance Through Optimisation Saves Operator 3.5 Rig Days, West Africa
Authors: Trulsvik Nils , Grant Lauren , Alexander Gregg , Alvarado Robert , Diffendaffer Waco , MacLeod Lindsey , Tetley Nicholas
Published: November 2017

An operator was planning to drill a 12¼-in. vertical borehole through highly interbedded shale and sandstone off the coast of Equatorial Guinea in deepwater West Africa. Offset data predicted bands of highly abrasive sandstone with unconfined compressive strength of up to 30,000 psi, which had resulted in multiple bit/bottomhole assembly (BHA) trips and associated nonproductive time (NPT). A new approach was required to find the optimal bit design that would drill the section in a single run whilst ensuring full compatibility with the planned BHA.

Offset wells were utilising heavy-set bits to offer greater abrasion resistance. The initiation of wear flats with such heavy-set bits had a detrimental effect on rate of penetration (ROP), particularly in the more-competent sandstone, and required high weight on bit (WOB) to drill ahead. This introduced harmful downhole drilling dynamics, which further accelerated any bit damage, leading to costly bit trips.

A time-based holistic modeling suite was used to capture the entire drilling system and push the boundaries of bit design to deliver optimal performance without sacrificing durability. A lighter-set drill bit was designed and validated using the modeling system to maximise dynamic stability over the benchmark. The new bit design and improved stability coupled with the latest cutter technology allowed the cutters to be kept sharp to deliver improved ROP and section length.

The 12¼-in. bit drilled 1,140.2 m—24% further than planned—in one run at an average ROP of 38.4 m/h. The bent-motor BHA maintained verticality throughout the section without any significant shock or vibration, and the bit was pulled out in good dull condition. The combination of new bit design and optimal BHA and operating parameters enabled the operator to complete the 12¼-in. section 3.5 days ahead of schedule, resulting in cost savings of USD 3.5 million.

Implementing holistic drilling system design and optimisation methodologies that consider not only the bit, but the entire BHA, drillstring, trajectory, and rock, can deliver proven performance in the most challenging environments.
Preventing Process Safety Repeat Incidents Driving better performance through embedded PS Incident learning
Authors: Sipkema Anthony W , Ahmed Arshad S , Salmani Mohamed AA
Published: November 2017

Oil and Gas companies, now more than ever, need to prioritize the prevention of process safety incidents. Finding root causes and learnings are not only cost-effective means of preventing repeat events from taking place, but also good business. Avoiding a costly incident (that would impact lives, money and the environment) is by far the most effective and controllable cost saving measure in the current volatile business climate.

Experience in PDO demonstrates that merely learning from incidents (LFI’s) is not enough to prevent repeat events from occurring. Only when these learnings are applied and embedded by staff on projects and in operations can they ensure that improvements occur.

The assurance that an LFI has been embedded (and truly learned) in the corporate systems is achieved through: Clear reporting requirements for AI-PS eventsMulti-disciplinary team investigations - lead by senior managersValidation of learnings and root causes by directorsCascading of key learnings via the online AI-PS Databook (with the ability to push and pull content)Corporate level assurance of actions embedded in new projects and work practices

A cornerstone in this learning journey was the retention of knowledge from our AI-PS investigations and senior management discussions and decisions. PDO developed a comprehensive online AI-PS Databook which contains all significant AI-PS incidents and their LFIs learnings from PDO’s own investigations, as well as regional and international incidents. Utilizing the SharePoint technology platform, the Databook helps provide in-depth access & search functionality to over 175 significant PDO Process Safety incident investigations (i.e. Tier-1 and HiPo) spanning back to 2000. It also contains over 3000 Shell LFI’s for further reference. Engineers, operators and indeed anyone in the business with a PDO email account could now access a fully assured learnings database to improve process safety delivery of their projects and activities.
Preventing Explosions and Sudden Breakdowns of Oil Filled Power Transformers by Packed Advance Oil Testing
Authors: Abou Ali Khaled Atef , Alrais Mohammed
Published: November 2017

Power transformer is critical electrical equipment in any electrical network, which is used for power transmission and distribution. Power transformer is static electrical equipment that can live for relatively long ages (25 years average) therefore it should be manufactured from high quality material and accurate design which will be costly (based on its size) and will take long for manufacturing and it is not shelf item. ADGAS electrical network has around 80 power transformers that supplies different voltage levels from 415 V to 33 KV. Although transformers are reliable equipment but there are three challenges for maintenance and operations teams that they can face with transformers. First, transformer cannot be dismantled easily to monitor its internal components and be proactive for any abnormality so it is hidden system. Second, even with reliable equipment there is possibility of faults and the consequences of transformer failure are massive as the consequences can be power loss, power redundancy loss, recovery time is significant, costly and has potential of explosion. Third, replacement decision is challenging as if the decision is only time based as the common practice (25 years) there is no guarantee that the transformer will fail before that period due to manufcuatirng issues/operational abnormalities/lack of maintenance, etc. Meanwhile; if transformers had proper operation and maintenance, then transformer can live much more than 25 years so replacement decision will be not efficient from cost wise. Therefore ADGAS electrical team is developing applying the best practices of transformer condition monitoring analysis and trending which will significantly enhance the safety, reliability and availability of electrical transformers. Applying condition monitoring will maintain the safety culture of ADNOC and meets with ADNOC four pillars as it will be described in details. The paper will start with simple definition for power transformer, discussing the potential hazards of transformers with accidents case studies. Then the paper will illustrate the existing solutions of controlling the hazards which is protection system and replacing old transformers. Then condition monitoring tools and results will be discussed thoughly and then the paper will conclude the project and shows its advantage and its role in applying ADNOC four pillars.
Optimizing Water Disposal: Case Study of an Integrated Multi-Disciplinary Project in the Jasmine Oil Field
Authors: Trekarnjanavong T. , Last N. , Edwards M. , Wasanapradit T.
Published: November 2017

The multiple challenges associated with a large scale offshore water disposal project are set out in this paper, which goes on to describe how these challenges have been overcome using an integrated multi-disciplinary approach that optimizes disposal well performance, while at the same time significantly reducing the OPEX associated with produced water handling. The difficulties associated with maintaining injectivity in the disposal wells have been overcome through a combination of strategies, including targeting alternative aquifer intervals, which lie above existing oil-producing zones, modifying the completion design, improving the water treatment process and implementing topside modifications. A comprehensive surveillance program has also been implemented to ensure that well and flowline integrity is maintained, and to understand the distribution of injection between the aquifers.

A key outcome of this project has been to scale back the requirement for high pressure water disposal (HPWD). The resulting low pressure water disposal (LPWD) strategy has achieved a cost saving of approximately $0.5 per barrel of oil produced which is highly significant in the prevailing low oil price environment.
Development of Engine Drivers for Unconventional Gas
Authors: Hall Kenneth
Published: November 2017

Objectives/Scope: Gas compression engine drivers used in unconventional resource development require the flexibility to operate with a wide range of fuels, in a wide range of conditions and with a high degree of reliability. This paper demonstrates the processes used to develop a modern medium speed engine driver and the technology leveraged to create an engine with the performance needed to be effective in unconventional gas applications. The resulting engine performance and operating envelop will be reviewed.

Methods, Procedures, Process: Engine manufactures have adopted varying strategies for dealing with the challenges new applications present. One manufacturer uses a disciplined, gate driven development process to move from identifying user performance requirements to delivering a fully capable and reliable family of engines that meets the needs of gas compression operators throughout the world.

The process for technology selection, laboratory confirmation and field validation is described. A system by system review of the selected engine technologies is presented, along with their specific contribution toward enabling the use of lower quality fuel gases found in unconventional developments while also enhancing other performance attributes.

Results, Observations, Conclusions: Laboratory data that demonstrates the validity of individual system designs and the entire functioning engine is provided. Areas of focus will include the benefits of smart fuel valves, real time NOx emissions measurement, the impact of lowering combustion air temperature through two stage intercooling and the effect of reducing the engine compression ratio through piston design and other techniques.

In addition to demonstrated engine performance in a laboratory setting, gas compression operators require an exceptionally high degree of reliability to minimize costs, maximize production and reduce operational uncertainty. The process used to validate the reliability of the compression driver in application is discussed, along with the findings of the field validation work and how the process drove changes to the final, production ready engine.

Lean burn and stoichiometric combustion technologies are reviewed, along with their impact on combustion design decisions and engine emissions. The complete engine combustion recipe for the new driver is reviewed in detail. Engine performance under varying extremes of fuel quality and other environmental factors is explained.

Another challenge in unconventional gas development can be the presence of hydrogen sulfide (H2S) in engine fuel at levels that cause damage to engine components. Engine configurations and operating regimes that help minimize the impact of H2S are discussed.

Novel/Additive Information: A new approach for increased compressor throughput by as much as seven percent during periods of lower ambient temperature is presented. The enabling engine technologies and operator strategies for leveraging this capability is described to allow new developments to take advantage of the engine/compressor potential.
Assessing Reservoir Quality of the Diyab Source Rock in UAE
Authors: Baig Muhammad Zeeshan , Van Laer Pierre , Leyrer Karl , Makrachev Gennady , Al Marzooqi Hassan , Al Suwaidi Salama , Raina Ishan , Dasgupta Suvodip
Published: November 2017

Diyab has served as the source rock for various major Jurassic and Cretaceous oil & gas plays in Middle East, and a number of recent studies have indicated that the Diyab formation has potential to be explored as an unconventional source rock gas play. This assessment is mainly based on 1) the known facies distribution, 2) lithology and rock properties, 3) source rock TOC and maturity 4) mud gas, and 5) Stimulation results. The objective of this paper is to identify the resource potential of Diyab source rock as an unconventional gas play in UAE.

Integration of valuable measurements is of upmost importance to reduce the uncertainty in reservoir quality assessment of any exploration setting. Quantifying TOC and maturity are one of the most important aspects in evaluating the source rock potential of an unconventional play. Due to the complexities seen in several source rock plays, assessing quality through interpreting mineralogy, porosity and water saturation can also be quite challenging. To achieve that, a comprehensive mud logging analysis program was carried out in the well complemented with a comprehensive and modern logging program combined with a detailed unconventional core analysis to identify rock properties, fluid type and saturations with the scope to assess unconventional resource potential of the Diyab formation in UAE.

Initial petrophysical evaluation shows that Diyab source rocks have a good Shale Gas resource potential within three different zones of interest in the Diyab formation. These zones of interest are based on, 1) Total Organic Carbon, 2) Porosity and 3) Saturation. During the petrophysical evaluation advanced mud logging analysis was used as initial calibration for TOC and mineralogy, a multi-frequency dielectric tool was used for initial saturation estimation and nuclear magnetic resonance analysis was used for porosity estimation and characterization. In the final computation, unconventional core analysis was used to refine and further calibrate the results. The level of gas saturation exceeds common pay criteria which are known to produce economic volumes of gas in other basins around the world.

Diyab as a source rock and as unconventional gas play in UAE in terms of reservoir quality has never been studied in detail. This is the first time that this kind of a comprehensive evaluation program was carried out using advanced log acquisition, advanced mud logging and specific unconventional core analysis and through this paper important aspects of reservoir quality for Diyab formation will be discussed and will be of great help for future exploration plans in the Diyab unconventional gas play.
How the CORE Project is Helping Drive a Culture of Continuous Improvement
Authors: Al Saadi Israa , Khan Shahla
Published: November 2017

Objective/ Scope

A commitment to continuous improvement lies at the heart of Dolphin Energy's business and the company places much responsibility on its employees to maintain this commitment at all times.

The launch of the company's cost optimization program, The CORE Project (TCP), in February 2016 was undertaken in response to the challenging conditions in the oil and gas industry and provided new opportunities to improve the company's financial performance. This paper will explain how TCP supports the company's commitment to continuous improvement by creating a ‘bottom up’ approach to drive collaboration through education, the development and use of cost saving processes and procedures and by rewarding employees and celebrating their success. The result of which has led to significant cost savings for the company.

Methods, Procedures, Process

The objective of TCP was to deliver cost savings to the company and enhance a culture of cost consciousness. To achieve this the onus of responsibility has been placed on the company's employees, tasking them to collaborate to deliver sustainable results and drive efficiency improvements through a long-term commitment.

This ‘bottom up’ collaborative approach to improve financial performance has been supported through the development of the following aspects, which helped create the right conditions for success:

Results, Observations, Conclusions

In the past 18 months, employees have generated more than 1,300 ideas, of which more than 260 ideas have been converted into cost saving initiatives without jeopardizing the safety of staff or the integrity of the facilities. This collaborative approach has not only demonstrated the value placed on a commitment to continuous improvement but created renewed commitment from employees to continue supporting the program in 2017, as evidenced by the results of a perception survey conducted earlier in the year.

Novel / Additive Information

This paper will help highlight tangible benefits that can be produced by creating conditions that encourage employees to drive a culture of continuous improvement.
Middle-Jurassic Carbonate Velocity Models in Saudi Arabia: Development and Validation
Authors: Alabbad Abrar , Ayadiuno Chris
Published: November 2017

Carbonate reservoirs are complex and require care in choosing an appropriate velocity model (Rafavich et al, 1984; Wang et al, 1991). Saudi Aramco has recently conducted a study to understand the effect of saturation and pore structure on the velocity of a particular Middle Jurassic carbonate reservoir in Saudi Arabia (Ayadiuno et al, 2015). As part of the study, several velocity models were empirically developed as a function of pore fluid type, density, and porosity. The study results suggested that at low velocity values, the obtained brine saturated core model correlated with Pickett while oil saturated core model correlated with Castagna (Ayadiuno et al, 2015). However, at high velocity values, the obtained models didn’t correlate with the published models. In addition, the study suggests that rock’s compressibility is less dependent on pore fluid type when the aspect ratio of the pores is high (Ayadiuno et al, 2015).

In this paper, three core-derived velocity models, developed as part of the earlier study (Ayadiuno et al., 2015), at 100% water saturation were extended and validated on the Middle Jurassic carbonate reservoir across four fields in Saudi Arabia. These models are: (1) compressional velocity as a function of total porosity (Model A), (2) compressional velocity as a function of bulk density (Model B), and (3) shear velocity as a function of compressional velocity (Model C). A total of 11 wells from four fields were selected to validate the velocity models. Fluid substitution was performed using log data and water as in-situ fluid to reduce prediction uncertainty related to the differences in saturation fluid type. In addition, we addressed the difference in scale between data used to develop the models (core plugs) and data used to validate the models (well logs).

Our findings are summarized as follows: (1) Model A, velocity as a function of porosity, is less sensitive to changes in rock stiffness and thus, is more reliable than Model B, (2) Model C, which predicts shear velocity, shows an overall better estimation of shear velocity than publicly available carbonate models from Castagna et al, (1985) and Pickett (1963). Thus, velocity models obtained from the study are more applicable to the four fields than published (Castagna and Pickett) models. The evaluation of these internally-developed carbonate velocity models across different fields shows a promising result in decreasing the uncertainty of velocity estimation in the Middle-Jurassic carbonate reservoir in Saudi Arabia. This work emphasizes the importance of assessing factors that affect acoustic properties, as well as the importance of multi-scale integration between core-plug measurements and logs.
PFLNG1 - Completing the LNG Value Chain Through Technology
Authors: Yussoff Wan Mohd
Published: November 2017

PETRONAS has developed a Floating Liquefied Natural Gas (FLNG) to capitalize and monetize on the availability of the gas resulting from the development of several gas fields in Malaysia. FLNG is a concept where there is an integration of the floating production, storage and offloading unit with LNG production facilities on the deck. It refers to liquefied natural gas (LNG) operations employing technologies designed to enable the development of natural gas resources located offshore. Floating near to an offshore natural gas field, the FLNG facility will be able to produce, liquefy, store and carry out ship-to-ship transfer of LNG at sea before LNG carriers ship it directly to markets. Since everything is carried out at sea, there is no need to construct any jetty, breakwater ar even LNG tank farms.

PETRONAS has taken a bold decision to embark on the first of its kind offshore LNG liquefaction facility. FLNG signifies PETRONAS’ technology advancement solution which adds value to marginal and stranded offshore gas resources which otherwise would be uneconomical to be developed, hence becomes a benchmark for the execution of similar-scale FLNG facility.

PETRONAS Floating LNG concept was envisaged to monetise stranded gas resources. The two floaters namely PFLNG1 & PFLNG2 for offshore Sarawak and Sabah respectively will increase the country's LNG production capacity by approximately 8% (2.5 MTPA). This paper will highlight the first FLNG developed by PETRONAS; the PETRONAS Floating LNG Satu (PFLNG1).

The PFLNG1 is designed based on a new built vessel rated for 1.2 MTPA LNG production capacities. The facility will receive feed gas from an identified gas fields which is operated by PETRONAS through a subsea pipeline at the water depth of about 77 meters. The design is based on a new built vessel with LNG storage capacity of 177,000 m3, condensate storage capacity of 20,000 m3. The design life for both hull and topside is for 20 years without the requirement for dry-docking. The hull was design in the ship-shaped form and adopted relevant marine standards and techical requirements.

Earlier, the PFLNG1 was constructed at a shipyard located in South Korea. Upon the completion of the construction phase, the facility was towed to site before it was hooked up to the sea bed using the turret mooring system. The facility will have a weathervaning capability which allows it to rotate 360 degree around the turret to ensure right heading during its operation.
Evolution of Reservoir Management and Development Strategy of a Giant Offshore Field in Abu Dhabi
Authors: Khan Muhammad Navaid , Al Neaimi Ahmed , Al-Shehhi Omar , Channa Zohaib , Ahmed Fazeel , Al Feky Mohamed , Sarsekov Arlen
Published: November 2017

Reservoir management has been defined in many different ways, such as, "a sequence of resource–deployment decisions made to maintain optimum economic recovery of petroleum", "the application of available technology and knowledge to a reservoir system in order to control operations and maximize economic recovery within given management environment", "rely on use of financial, technological, and human resources, while minimizing capital investments and operating expenses to maximize economic recovery of oil and gas from a reservoir" (Thakur 1996) etc. Overall, the whole purpose of reservoir management is to help oil companies make the best decisions to meet specific objective using all the available resources.

Essentially a reservoir management & development strategy is comprised of various elements; however, the purpose of this work is to shed light at the key elements, which were recently revisited to tackle the evolving changes in reservoir conditions for a giant Abu Dhabi Field, with a development and production history of over 50 years. The intent on this paper is to share the unique methodology adopted to address the sector-based reservoir performance and to generate the relevant opportunities to tackle the pertaining issues.
Integrated Sand Control Technique Utilization of Thru Tubing Sand Screen and Wellhead De-Sander Technology
Authors: Malau Aldani , Sutarto Balok , Ghozali Farid , Istono Noviadi , Sukotrihadiyono Tejo
Published: November 2017

LN field is a gas field located in South Sumatra, Indonesia. The conversion trial from medium pressure to low pressure tested at the field in 2009 unfortunately led to sand carried out from formation. Wellhead de-sander and production rate control since then have been initially used as a preliminary effort to reduce the sand production. Due to depleted reservoir pressure and limited availability of formation core, down-hole sand control selection was very challenging. The condition initiated fluid losses during the well service and inability to conduct compatibility testing prior to applying sand control method such as resin coated sand, gravel packing or frac-packed. In addition to well head de-sander as to improve the sand control quality, thru tubing sand screen method has been selected as a unique alternative to face the sanding problem for LN field condition. Rig-less installation and flexibility of sand screen replacement were the main reason why this method was finally selected.

Thru Tubing Sand Screen was installed using regular slick-line unit. The sand screen was installed very close to end of tubing (EOT); it set just around 2 feet above EOT. Special tubing packer was set with a non-explosive setting tool technology with a battery-operated and time-based device.

Since the particle size distribution of sand for sieve analysis was taken from surface sampling, the possibility of sand passing thru the sand screen or sand plugging the screen was still high. But, the thru tubing method provided easy way to install or uninstall the sand screen while wellhead de-sander provided double protection to prevent sand travelling and damaging the surface facilities.

This paper will share on how the down-hole sand control study was conducted, how the sand screen and the wellhead de-sander designed, the installation and optimization process and the success story of the implementation at LN field before it is concluded as an integrated sand control technology,
A Step towards to Minimize Environmental Footprint: An Innovative System to Dispose Generated Cement Waste on a Zero Discharge Artificial Island
Authors: Singh Rudra Pratap , Khalid Al-Wahedi , Al Kindi Rashid , Bassam G Elatreche , Cesetti Maurizio , Jose Alzate , Benygzer Mhammed , Haddad Mohammed , Hassan Mohammed , Kirby Cliff , Paila Phalgun , Suleiman Ala , Ruzhnikov Alexey
Published: November 2017

Because environmental regulations are rapidly evolving towards stringent requirements, oil and gasoperators are confronted with a great challenge of disposing drilling waste, especially when operating on an artificial island located 120-km offshore and under a Zero Discharge Policy. The paper describes an innovative engineering solution that significantly reduces the time, cost and the associated safety hazards with disposing of the cement waste generated from primary cementing operations and drilled cement cuttings.

The earlier disposal process implemented on the island included collecting, storing, and shipping the cement waste to an onshore treatment facility. This process was proven to be cumbersome, time-consuming and extremely expensive. Additionally, external factors such as logistics constraints, weatherconditions, and storage skips availability had a direct negative impact on the process, resulting in a massive accumulation of waste on the island. On the other hand, the newly developed disposal process utilizes existing resources, with minor modification, within the artificial island. A step-by-step procedure was developed to dispose all excess cement and drilled cement cuttings generated without any negative HSE impact.

A pilot trial was performed successfully by injecting the cement waste into the shallow loss zone through the annulus, and therefore, the process was generalized to both island and found to be safe and efficient operationally and economically. The new innovative method simplifies the disposal process to a one-stage operation that is performed along with the primary cementing operation. By implementing the process, no cement handling on surface is needed, resulting in a 90-percent drop in the cost.. The number of people involved is reduced as well. Consequently, a reduction in the hazard exposure and the potential lost time incident (LTI) is achieved.
Asset Optimization Using Downhole Corrosion Sensor for Electrical Submersible Pumps
Authors: Chandran Ashwin , Liu Yi , Monteiro Othon , McClain Scott Thomas , Liu Zhengwei , Krueger Sven
Published: November 2017

Corrosion and related issues are a major contributor in failures of electrical submersible pumps (ESP). This paper describes the development and preliminary testing of a new downhole corrosion sensor to be integrated into ESPs for providing continuous monitoring. We will describe the development of a downhole sensor, testing and applications of such a sensor. In-situ corrosion monitoring provides valuable and actionable data that enables implementation of mitigation strategies before damages occur and allow for planned servicing. It ultimately allows operators to make informed decisions on corrosion control and ESP maintenance scheduling.