bluuebunny/crossref_metadata_2025 huggingface dataset:
Diagnostic Rules for Gas Turbines Driving Centrifugal Compressors
Authors: Ashour Osama , Saravanapriyan Arul , Khalidi Abdurrahman , Fadlun Ever , Giannini Nicola , Ceccherini Alberto , Pierir Marco , Bianucci David
Published: November 2015

Diagnostic rules for online monitoring of turbocompressor trains driven by gas turbines are presented. These rules cover components and zones that are most susceptible to failure, such as combustion elements, hot-gas-path- exposed wheelspace area, and dry gas seal components. The effect of these rules on improving the availability and reliability of such machines are also explained. Various case studies using real operational data are shown, and emphasis is given to explaining how to use the rules in diagnostic and prognostic studies. The rules can be divided into availability and performance rules. For the gas turbine, engineering performance rules covering the axial compressor, output parameters, and fuel consumption are introduced. Availability rules covering combustion and the wheelspace temperature are discussed after that. For the centrifugal compressor, rules covering the dry gas seal components are presented. Both theoretical and practical considerations are given to optimize the rules' output in terms of accuracy, ease of implementation, and value to the end user. All presented rules are based on physics and probabilistic methods and are not based on simple thresholds.
The Complexity / High Profile Drilling of the First ADCO Exploratory Well in Salt-Dome Island, HP/HT, with Limited Data"2D Seismic Lines
Authors: Hegazy Gehad Mahmoud , Salama Eid , Al Marzouqi Muna , Ganda Sukesh
Published: November 2015

The objective of this paper is to present the achievements and lessons learnt from a field case study of drilling an exploration well through salt dome with limited data. Also this project introduced drilling with a high efficiency and ‘out of the box’ thinking to deliver a project, that was categorized as high risk and high cost, with optimum cost and zero nonproductive time.

This complex and high profile project was executed against limited time, data and resources. HSE initiatives and innovative ideas to solve engineering and logistical problems were implemented. The project team demonstrated the ability of organization to adapt and succeed when presented with a unique challenge.

The paper will highlight the development of the capabilities of Abu Dhabi Company for Onshore Petroleum Operations Ltd. (ADCO) to drill for the first time from an island and within the salt dome that was critical to support high risk and high cost 3D seismic for future development plan for this area.

The study presents a newly discovered area and the success of this well that has opened a new exploration play into hydrocarbon resources with a high potential economic impact.The paper will highlight the achieved milestones, such as well Design and drilling through the most complex salt dome well thus far drilled in the UAE. Industry experience dictates that salt drilling presents unique challenges and hazards.
Understanding and Overcoming Challenges of Carbonate Reservoir Matrix Stimulation – The Case of an Offshore Abu Dhabi Reservoir
Authors: Ali Issa Abdelkerim , Uematsu Hiroshi , Bellah Samir , Al-Farhan Zahra A. , Al Hashemi Mohamed A.
Published: November 2015

A mature offshore Abu Dhabi oil field produces from a heterogeneous carbonate limestone reservoir with an important column of bottom aquifer. The reservoir heterogeneity is characterized by presence of kurst filled with fine materials at top section, conductive faults, fractures, and significant variation of other rock properties. Most of the main faults cross from the top of the oil column all away down to the bottom of the aquifer. Meanwhile, the field development mainly consisted of horizontal producers targeting the upper section of oil column with peripheral deviated water injectors to sustain reservoir pressure. Generally, producers start with high initial oil rates, but the early decline is steep due to rapid water cut increase resulting into lower well head pressure. Production profiles from PLT combined with FMI indicate that production and water influxes are contributing mainly from the fractured sections of the horizontal drain or through conductive faults. In the meantime, important matrix segments of horizontal drains present very low or no contribution to production. As a solution, surface bull heading and targeted zonal stimulations were performed, which yielded mixed results.

This paper focuses on the analysis of the latest targeted matrix segment stimulation results, which include candidate selection background, description of stimulation method and operations, pre and post stimulation production performance analysis, analysis of main factors affecting carbonate matrix stimulation, and a summary of findings with overall implication to carbonate reservoir matrix stimulation.
CwD Technology Improves Economics in Tight Gas Exploration Project in the Sultanate of Oman
Authors: Briner Andreas , Busaidi Yazeed , Adawi Anwar , Hilditch Robert , Sanchez Francisco , Sanderson Martin , Refai Ahmed , Adly Essam , Nadezhdin Sergey
Published: November 2015

In Sultanate of Oman, use of a casing-while-drilling (CwD) service improved project key indicators for a complex unconventional tight gas exploration project. The technology has been used in 12 wells to date, and the improvement progress has been tracked from the first well. Reaching first hydrocarbon-bearing zone in northern Oman required drilling through the unstable thick Shagri shale, principal element of the Fiqa Formation. Formation swelling and collapse were encountered in the first exploratory wells, which caused significant nonproductive time for reaming and additional trips in hole. To complicate the situation, the naturally fractured UmUeR Formation, located above Shargi, could cause either partial or total losses when drilling conventionally. CwD technology was the selected drilling approach for the subsequent wells in an attempt to mitigate these issues. Although drilling through unstable Shagri shale was still possible with conventional drilling, reaming, stuck pipe and unplanned casing depth become routine operations. The proposed drilling approach proved to be an economically sound alternative to conventional techniques used previously in the field to reduce risk and associated cost. In the Sultanate of Oman, the CwD technology reduced the time of drilling and casing surface holes by 40% in comparison to the field average when using the conventional drilling technique. After drilling 12 subsequent wells with CwD technology, the operations team reported saving of up to 4.94 days per well. Efficiency analyses were conducted, and the technique was fine-tuned for specific conditions.
Pilot Plants: Acid Tests for Researchers in Pushing New Technologies Towards Commercialisation
Authors: Mohd Shariff Shahidah , Abai Mahpuzah , Ishak Mohd Adaham , Lan Lim Fong
Published: November 2015

In any R&D projects, the researchers begin with a Proof-Of-Concept where the research proposal is subjected to scrutiny by a team of experts. If it passes muster, it is then nurtured through stages of development, piloting, deployment and ultimately, commercialization. In PETRONAS, the researchers' share of work has never been confined only at the lab. Once the work has been scientifically or technically proven at lab scale, they are pushed to the hard part of looking into the practicalities and economics of applying the technology into the real world.

Piloting of a technology is a challenge for researchers who have to move beyond their comfort zone of "pure" research to look into a host of factors that determine the success of real life applications of their work. There are countless parameters to consider ranging from costs to risks. Researchers are also expected to forego their "dream" for a perfect technology and accept the imperfections with calculated risks in order to move the technology to the next level. They are anticipated to provide mitigation plans for the risks that come together with the technology deployment to meet every aspect of the safety requirements. The minds of the researchers have been instilled with one clear goal in their pursuits of technologies – bringing them beyond the lab to be deployed in the fields, where they can add values to the Businesses.

To date, PETRONAS has successfully deployed more than 5 pilot plants on various R&D areas to several plant operating sites in Malaysia. This has kept the researcher teams busy and on their toes with the challenges and triumphs of seeing new technologies go live and subjected to real operating conditions. In every step of pushing a technology from lab to pilot and up to commercialization, the researchers have gained many important traits from the science, economics, engineering, operation and commercialization of the technology, hence, producing "all-rounded" researchers. The process pushes them to work and understand the requirements of not only their fellow researchers, but also those people of different backgrounds from engineers who turn their R&D concept to pilot unit to commercial personnel who needs convincing in order to sell their technology.

Through researchers' involvements from lab-scale to pilot, and often up to commercialization of the technologies, a significant leval of knowledge and skill has been acquired together with the developments of tools and methods to successfully deliver new technologies.
Detailed Discrete Fracture Network in Support of Drilling Activities in North Kuwait Carbonate Reservoirs
Authors: Richard P. , Pattnaik C. , Al Ajmi N. , Kidambi V. , Narhari R. , LeVarlet X. , Guit F. , Dashti Q.
Published: November 2015

The North Kuwait Carbonate Reservoirs (NKCR) are currently under development by KOC (Kuwait Oil Company). The appraisal and development of the NKCR offer challenges such as lateral variations in reservoir quality, tight to very tight reservoirs and natural fractures with a high degree of spatial variations. The presence of open, connected fractures is one of the key elements to achieve a successful development. Also, the presence of fracture corridors increases the risk associated with drilling. Numerous fracture modelling studies have been supporting both appraisal and development strategies of the fields.

This paper illustrates how small sector scale detailed DFN (Discrete Fracture Network) can support the planning and drilling activities of future appraisal wells.

A series of detailed DFN models has been built around existing wells. These DFN models are based on a thorough structural understanding combined with a detailed fracture characterisation using bore-hole image (BHI) and core data around the wells of interests. In addition to the fracture characterization work, mechanical stratigraphy has been developed using E-facies and geomechanical logs. Fracture connectivity analysis has been carried out to calibrate the DFNs to the static and dynamic well data. DFN models have also been created around appraisal well locations based on the calibration with the existing wells. These DFN models are now being used to communicate with drilling in order to illustrate the potential distribution of fracture corridors in the sub-surface. These DFN models are also helping to improve the placement of the planned wells with respect to their associated risks and objectives.
Development of a Giant Carbonate Oil Field, Part 1: Fifty Years of Pressure Maintenance History
Authors: Pavangat Vimal , Patacchini Leonardo , Goyal Praffula , Mohamed Farzeen , Lavenu Arthur P. , Aubertin Fabrice , Nakashima Toshinori
Published: November 2015

The giant field considered in this paper, located offshore Abu Dhabi, has so far been developed with solely a pressure maintenance-oriented strategy despite having produced for nearly fifty years. Such achievement has been possible because the field, divided into three stacked isolated reservoirs, is relatively homogeneous with little-to-no flow barriers.

The purpose of this paper is two-fold. First, propose a review and critical discussion of the different pressure maintenance methods employed so far, which chronologically include gravity-driven dumpflood water injection, peripheral powered water injection, and down-flank as well as crestal gas injection.

Second, present a segmentation mainly based on pressure trends on which injection-production metrics can be computed to help reservoir management pinpoint areas lacking support. A key to such analysis in the presence of peripheral water injection is to account for efficient water only, i.e., discard losses to the aquifer. For this purpose, a workflow involving streamline based post-processing of reservoir simulations corroborated by material balance analysis is used.

Recent increasing trends in WCT and GOR indicate that a development solely based on pressure maintenance and reservoir energy (i.e., without artificial lift) is not sustainable anymore, and must transition to sweep-oriented. Plans for such migration are discussed in the companion paper of Nakashima et al. (SPE-177801).
Critical Assessment of CO2 Trapping Capacity Under Gravity Segregation with Capillary Heterogeneity
Authors: Park S. S. , Kim T. H. , Cho J. , Lee K. S.
Published: November 2015

CO2 trapping mechanisms in geologic sequestration have been typically categorized as structural, residual, dissolution, and mineral trapping. However, a storage analysis with fine-scale heterogeneity requires an investigation of newly suggested mechanism, capillary trapping. In addition, CO2 injection process, in which gravity force is relatively strong compared to viscous force, leads to severe gravity segregation and poor contact volumes. This study covers an integrated assessment of CO2 trapping associated with gravity number in heterogeneous formations.

Numerical simulations have been undertaken to evaluate the CO2 trapping efficiency. The effects of formation properties on various CO2 trapping mechanisms are studied with different injection scenarios. Leverett J-function is applied to take account of capillary heterogeneity. Inclusion of capillary trapping enables considerable amount of CO2 to be secured by local capillary barriers. To examine the effects of CO2 gravity override, gravity number, a ratio of gravity to viscous forces, has been introduced. The amount of trapped CO2 and leakage are quantified with the gravity number determined by average permeability, ratio of vertical to horizontal permeability, and injection rate.

Since the overall values of capillary entry pressure are higher in the formation with lower permeability, the larger portion of the lower aquifer can act as capillary barriers, which lead to a large accumulation of CO2 by capillary trapping. Low ratio of vertical to horizontal permeability enables the CO2 plume to spread out more laterally, thus enhancing the CO2 trapping capacity. Under low injection rate, the injection pressure does not have significant impact on the fluids flow and gravity force is dominant. It induces the gas to flow upward shortly after injection, which results in an accelerated CO2 leakage. As the injection rate is higher, stronger viscous force allows the gas to migrate mainly in the horizontal direction. It causes the gas to contact a larger area with brine, so that the amount of trapped CO2 increases. The portion of capillary trapping reduces from 51% to 17% as the gravity number increases. By residual trapping, the immobilized CO2 are 13% and 28% for high and low gravity numbers, respectively. In comparison with residual and capillary trapping, the dissolution of CO2 is insensitive to the parameters associated with gravity number.

For the successful evaluation of CO2 trapping capacity in heterogeneous domain, the results have proven the importance of capillary trapping which accounts for the largest portion of CO2 immobile phase. Integrated assessment of CO2 migration with gravity number is particularly useful to improve the accuracy of CO2 leakage estimation. The workflow will provide simple parameter sensitivity to aid engineers in optimizing CO2 storage design.
Improved Reservoir Management Practice Using Reservoir Performance Indicator Based On the Dynamic Model Uncertainty Study
Authors: Arii H. , Baslaib M. A. , Keshtta O. , Ben Sadok A. , Attia M.
Published: November 2015

At first, the risk assessment of dynamic model parameters based on uncertainty analysis was conducted to evaluate the impact of the reservoir uncertainties in a carbonate reservoir, offshore Abu Dhabi. The study showed that the evolution of gas to oil ratio (GOR) was a main reservoir response that affected the future production profile; hence it is the focus of this paper. It is important to track the GOR behavior in the field, to compare the actual reservoir performance with the risk assessment results and to evaluate the proper reservoir management and development options.

Uncertainty analysis was used to evaluate future GOR performance and its probability of occurrence. The range of production plateau duration was also quantified. Therefore, future GOR performance impact on production for all probability ranges can be estimated.

Finally, "GOR performance indicator" was developed by use of GOR upside and downside performance curves generated as a result of uncertainty studies.

More than three years of monitoring GOR evolution by use of the developed GOR performance indicator allows the assessment of GOR behavior trends against the expected performance, which permits the development of adequate reservoir management plans. The GOR trend can be explained as a result of reservoir management actions such as optimizing gas injection rate, adjusting well production rate and closing high GOR (HGOR) oil producers. Accordingly, the GOR trend can indicate the current reservoir performance compared to the range of uncertainty analysis. It also can put light on required reservoir management action plans for operations and assist building assurance of the reservoir development.

Consequently, the developed "GOR performance indicator" is based on the reservoir simulation outputs for uncertainty analysis. In case that the GOR trend is deviating from the range of the GOR performance indicator, the reservoir simulation inputs needs to be modified.

The developed GOR performance indicator is considered useful to foresee required reservoir management action plans and to suggest alternative development plan needs in case of unfavorable actual reservoir performance. It is noted that the GOR performance indicator can be updated based on new information available. Additional data gathering can support to narrow uncertainty ranges.
Gas Injection as an Enhanced Recovery Technique for Gas Condensates. A comparison of three Injection Gases
Authors: Kumar A. , Gohary M. E. , Pedersen K. S , Azeem J.
Published: November 2015

Gas injection is a recognized enhanced recovery technique for oil reservoirs, but has been given less attention for gas condensate fields. If a gas condensate is produced by natural depletion, the condensate-gas ratio of the produced well stream will steadily decrease after the saturation pressure is reached. The liquid condensed will stay back in the reservoir and will not be produced.

A laboratory study was conducted for a Middle East gas condensate reservoir fluid. Three different injection gases were used- N2, CO2 and a lean hydrocarbon gas. A gas revaporization experiment was conducted with each gas on the depleted reservoir fluid. The gas revaporization experiments showed that injection of CO2 made the liquid dropout in the PVT cell decrease substantially. Already condensed liquid was revaporized and led to an increased liquid content in the released gas. In small concentrations N2 made the liquid dropout increase, but with a continued injection of N2 the amount of liquid dropout declined. The hydrocarbon gas made the liquid dropout decrease at all concentrations, but to a lesser extent than CO2. An analysis of the results showed that injection of CO2 and a lean hydrocarbon gas may substantially increase the liquid recovery from the actual field, while it is questionable whether N2 injection will have much impact on the liquid recovery.
Steerable Drilling Liner Matches the Industry's Common Theme Regarding Cost Optimization Approaches and Minimize Geomechanics Related Challenges; Technology Overview, Applications and Limitations
Authors: Sherbeny Wael El , Dabyah Ali Al , Ghai Gagan , Merie Ibrahim
Published: November 2015

Because fracture gradient changes with rock type, some formations are more sensitive to induced fractures than others. Depending upon depth, the fractures created will either be horizontal or vertical. If the depth is 2500 feet or less, horizontal fractures are usually produced. Because horizontal fractures require lifting the entire overburden, they are limited to shallow depths. At depths over 3500 feet, fractures are usually vertical. Because vertical fractures occur without lifting the overburden, they can be created at much lower pressure. The propagation pressure is generally much less than the pressure that would be required to initiate the fracture. Consequently, fracture losses, once initiated, are difficult to control.

Wellbore instability, particularly in shale formations, is a major challenge in drilling operations. Many factors such as rock properties, in-situ stresses, chemical interactions between shale and drilling fluids, and thermal effects must be taken into consideration in well trajectory designs and drilling fluid formulations to mitigate wellbore instability-related problems.

The Steerable Drilling Liner service combines a rotary steerable system with a liner to help overcome the challenges: drilling in zones with lower pressure and unstable shale/coal layers, and with formations of varying flow and pressure regimes. Running the liner while drilling keeps the wellbore stable and eliminates the need to pull the drillstring to run casing. This is how it reduces your risks and NPT, saving the costs associated with contingency plans. Because the liner is isolated from the reamer shoe, you can rotate the liner at much lower RPMs than the pilot and reamer bits. This design lessens the load on the liner, improving its fatigue life.

The Steerable Drilling Liner steerable drilling liner service helps you to mitigate the risk of hole collapse and formation damage by reducing openhole exposure, Reduce NPT by eliminating extra trips and ensuring that the liner is installed at TD from the first run

Enhance wellbore integrity by drilling with the liner, leading to the plastering effect, which reduces fluid loss and cuttings volume, Lower health, safety, and environmental (HSE) risks by reducing pipe handling and rigsite footprint size

Steerable Drilling Liner service developed and qualified using a rigorous processes including extensive onshore testing at the service provider Experimental Test Area (BETA) facility before being successfully deployed offshore. Rely on Steerable Drilling Liner service performance in extreme environments; the cost-effective Steerable Drilling Liner service promotes wellbore stability and performs reliably in the challenging downhole environments. This Paper will reveal the technology overview, updates, case histories and field limitations
Ecological and Environmental Management During the Hail 3D Transition Zone Survey; Safe Working Practices Within a UNESCO World Biosphere Reserve
Authors: MacGlennon G. S. , Nilsson P. B. , Casson G. A.
Published: November 2015

The Hail 3D seismic transition zone survey, carried out by ADNOC in 2013/2014, was located within an area considered to be of significant national and international environmental importance. Falling within a designated marine protected area ratified by Abu Dhabi ministerial decree as well as a UNESCO world biosphere reserve, high standards of environmental and ecological management throughout the acquisition programme were of paramount importance.

Effective environmental and ecological management throughout the project was attained via the design and implementation of numerous working procedures and monitoring programmes. These included the development of a specific sets of mitigation guidelines for use during transition zone surveys for minimising disturbance and injury to marine mammals and turtles and operating within mangrove areas, the use of environmental profiling, auditing and post operational monitoring, in both the terrestrial and marine environment for collecting new data on the biodiversity and ecology of the area.

For the first time we present ecological and environmental data collected over a period of 12 months within the Hail shoal area. In addition to data on species numbers and distributions we present a method for effectively managing complex seismic surveys being carried out simultaneously in both the marine and terrestrial environment.

For marine mammal and turtle species our results demonstrate seasonal variation in total numbers throughout the year but no significant reduction in observed numbers occurring as a result of seismic exploration activities.

We further demonstrate how a complex seismic survey can be managed and supervised to mitigate and minimize environmental footprint or negative impacts on biodiversity as a result of the exploration and resource development considered crucial to the socioeconomic development of Abu Dhabi.
The Role of Pilot Projects in the Development of Unconventional Resources
Authors: Addis M. A. , Freitag H-C. , Mendez A. , Ceccarelli R.
Published: November 2015

This paper addresses the challenges that sub-surface and asset managers face when evaluating shale and tight gas developments during the E&A stage of a project, of having limited confidence in the production predictions, and consequently the potential revenue stream, whilst needing to quantify the sub-surface uncertainties through the commitment of a large number of wells—and costs—to assess and develop the resource.

Conventional field developments rely upon both well production tools and dynamic reservoir models to estimate the production from development wells through the life of the field. In sharp contrast, the development of unconventional resources, in practice, is less reliant on these models as they currently lack the underlying physics and functionality to model the additional complexity associated with unconventional resources. Additionally, much of the required input data for these models (such as the desorption isotherms, the hydraulic fracture geometry and performance as well as the natural fracture geometries and conductivities) are absent particularly during early appraisal and development.

The approach commonly used to reduce the uncertainty of these developments at the evaluation stage is a modification of the stage-gate process, through the inclusion of structured pilot projects. This provides a commercial basis for full field developments in the absence of reliable ‘class A’ production models.

The paper also considers key technical uncertainties for shale gas and tight gas developments which can be assessed through pilot projects, in order to quickly evaluate the viability of a development: Of primary importance in these unconventional resources is the absence of a significant natural permeability and lateral and vertical heterogeneity, the economic consequences of which affect the methods by which these resources are assessed and developed. Sub-surface and project uncertainties that may impact the viability of developments are discussed including; water and fluid management and environmental impact assessments. Data gathering and monitoring and surveillance requirements are reviewed based on current technology in the context of reducing project and development uncertainties.

The paper describes the approaches through which the production potential for an unconventional resource is evaluated through a multi-well commitment, while limiting the risk and cost exposure for the operating company.
Successful Delivery of Downhole Measurements from Abu Dhabi Giant Offshore Field
Authors: Newton Daniel , Pandian Senthil , Katheeri Zaid Al , Kofoed Curtis , Gurses Sule , Demyanov Alexandr , Kozin Anton
Published: November 2015

The paper presents successful installation of Permanent Downhole Gauges (PDGs) and Distributed Temperature Sensing (DTS) technologies for the first 13 wells, data transmission method of gauges data via mobile network and application used to receive and store the data with visualization software in an Abu Dhabi giant offshore field.

As a part of the plans to increase production and reserves recovered from the field, extended reach wells are planned to be drilled off four artificial islands. The project includes a series of oil producer wells along with water injectors. Gas lift will help to sustain the production level after the initial period of natural flow. During the planning phase, it was identified that efficient management of gas lift operations can be achieved through DTS. In addition, 2 single-point pressure and temperature data points from PDGs were to be acquired to assist in reservoir management efforts and calibration of the DTS.

The solution provided for each well was to deploy tandem high resolution tubing pressure and temperature gauges run on a hybrid permanent downhole cable containing tubing encapsulated conductor (TEC) plus fiber optics for DTS. The hybrid cable serves as a power and communication line to the gauges installed above the production packer at measured depths varying from 10,000ft to 20,000ft as well as providing distributed temperature measurements across the upper completion through a multi-mode fiber. The temperature data will be used for gas lift operations surveillance and optimization. An additional fiber is installed for distributed acoustic sensing for future well integrity surveillance purposes.

As of August 2015, the first 13 wells have been installed successfully in the field with PDGs and Fiber Optic monitoring. The gauge data (pressure and temperature) is planned to be delivered through a GSM network transmission system into the onshore office node at the operator headquarter (HQ). The focus has been on integration of different components of surface system like Data Acquisition Unit, Remote Terminal Unit (RTU), GSM Modem, Virtual Machine (server located in the onshore office) and fully customized Human Machine Interface (HMI) software. The new approach allows for continuous real time monitoring of data at the HQ and taking necessary actions in a timely and efficient manner.

Initial stage of project implementation has shown successful results with all PDGs and Fiber Optics operational in all wells and improved execution efficiency of field installation. Well completion designs are planned to continue with the same gauge and fiber optic design for the duration of the field development.
Integration of Young UAE Nationals in Commissioning Grass Root Refinery
Authors: Alhammadi Adel Ali
Published: November 2015

Objectives

The objective of this paper is to highlight the development & role of young Emiratis during commissioning of new refinery with integrated process units. This opportunity provides them the right platform to play a vital role & to create futuristic national manpower with strong national integrity, competence & leadership to adopt modern technology, a culture of participation and ultimately to contribute as proud Emiratis.
Lab Experiments and Simulations for Multiphase Flow Splitting from a Single Flowline into a Dual Riser
Authors: Henkes R. A. , Worthen R. A. , Ellepola J. H.
Published: November 2015

A possible new development concept for Floating LNG may include a single flowline along the sea floor that splits into dual or more flexible risers. Since the gas co-produces condensate and water, design rules are needed for the splitting of the phases at the riser base manifold. Multiphase flow splitting is much more complex than single-phase flow splitting. The latter is fully determined by the back pressure on each riser, but for multiphase flow the phase split (Liquid-Gas Ratio) into each of the risers may also depend on other factors, such as the flow regime in the riser/flowline, the precise geometric details of the splitting configuration and other parameters (e.g. the momentum flux ratio in the flowline). Ideally the phase volume ratio should be fully equal over the two risers and remain the same as in the flow line. To find the proper design rules for multiphase flow splitting, which ensures equal phase volume split, we have set up a research programme that includes lab experiments and simulations using Computational Fluid Dynamics. The hypothesis is that phase maldistribution can occur if the gas flow rate in the risers is so low that it gives churn flow or hydrodynamic slug flow in the risers, whereas an equal phase volume split is expected if the gas flow rate is sufficiently high to produce annular flow in both risers.

The flow facility at the Shell Technology Centre in Amsterdam transports air and water through a 2", 100 m long flowline, splitting into dual, about 15 m high, risers, having a diameter of 2". The pressure is atmospheric at the riser top. For the splitting configuration, we used a symmetric lay-out, which is a so-called Impacting Tee. We created the splitting curve by systematically changing the opening of the chokes at the top of the risers. At low gas flows a non-symmetric flow split was found, with flip-flopping and hysteresis in the risers. For example, a stagnant liquid flow could develop in one riser, and churn flow in the other riser, with a sudden swap of flow behaviour between the two risers. This maldistribution gradually disappeared as the gas flow rate was increased.

CFD simulations were carried out with the Fluent package using a Volume of Fluid approach for the multiphase flow through the symmetric splitter. As in the experiments, the CFD simulations also give the preference of all flow to be produced through a single riser, with a stagnant liquid column in the other riser. In the experiments this maldistribution disappeared for a sufficiently high gas throughput. For the first flow rate where an equal split is found in the experiments, however, the CFD model still predicts that all of the flow exits through only one of the two risers.
Addressing the Challenges of Sourcing Water for Hydraulic Fracturing by the Use of Membrane Technologies
Authors: Basu Shiladitya , Franks Rich , Shin David , Boda Roman , Bartels Craig
Published: November 2015

Operators in the Middle East have embarked on projects to explore and produce oil and gas from unconventional reservoirs by hydraulic fracturing (fracing). Many unique challenges exist for each reservoir under consideration but one that is common amongst all of these operations is the access to water to frac with. Companies responsible for conducting the frac have learned a lot about water management through the experience gained in North America about using sources other than fresh water such as brackish water, flowback water, and produced water but often the required level of treatment is minimal. This is because there is access to fresh water, which allows for dilution to get the waste water to the minimum required level for use in a frac. This coupled with advances in the development of high salinity tolerant frac fluid chemicals (Lebas et. al. 2013) eliminates the need to use advanced water treatment processes such as membranes.

In contrast, there are many barriers to similar long term access to fresh water sources in the Middle East. Therefore other water sources must be considered, such as subsurface brackish water or seawater, and subsequently other treatment options must be considered, such as membranes. These technologies are mature in many other applications but for this particular application, there are challenges with implementing and deploying these systems resulting from the required flexibility of the systems and the environment in which the systems are to be operated.

In order to overcome these obstacles, it is important that the stakeholders openly communicate the expectations to develop a mutual understanding for the requirements of these systems such that design measures can be implemented and operating protocols can be developed to make the systems fit for the purpose. The authors of this paper have taken the approach of identifying likely issues and providing an approach to the design of the process and operational protocol for these applications to provide guidance to those considering utilizing these processes. Also, references are made to similar challenges faced in other applications to those in this application to help with identifying possible solutions. The goal of this paper is not to provide solutions to each and every scenario, because it is impossible to do so, but rather to identify the critical factors that should be considered to enable the project stakeholders with the tools for development of a good design and operating protocol. By providing some clarity to the risks and potential solutions it is the authors’ ambition that those who make the investment in the technology are able to obtain the expected results and return on their investment.
Evolution Of An Integrated Production System Model (IPSM) In A Greenfield Oil Environment
Authors: Al Jumah Ali , Lalji Farhad , Johan Josey , Hindawi Kareem , Al-Ibraheemi Abdulameer Turki , Tahir Abed Basim
Published: November 2015

Description

The field in question is a super giant oil field located in Southern Iraq. Historically, the field had 27 wells, along with surface facilities capable of processing ca. 100kbbl/d of oil. An additional processing facility was installed and some 18 additional wells were drilled and completed in the period 2012–13 to increase production levels in the field to more than 200kbbl/d, referred to as First Commercial Production (FCP). The field was shut-in for approximately 14 months during the pre-FCP period.

Initially, only scarce historical pressure, well test and production allocation data existed and so an approach to prove up, manage and optimize field production performance was developed using Integrated Production System Modelling (IPSM). This involved both surface and subsurface disciplines collaborating to integrate stand-alone models and discipline data from operations, production technology, reservoir engineering, petrophysics and production geology into a single integrated model for proving up well capacity, field surveillance and optimization. Initially, the individual discipline model definitions were based on design case and oil field theoretical assumptions combined with single point(s) of actual data points. As more field data was collected the various models were updated and re-calibrated to ensure a maximum deviation of 10%.

Over the past 3 years, as the field has transitioned from the pre-startup phase to the stable production phase and with this has been the evolution of the uses and application of the IPSM. This paper will describe the data gathered, process of model calibration, uses of the model in the four key phases to date along with the future aspiration case:

Generally speaking, the main objectives of building and maintaining an integrated production system model are:
Begin with the End in Mind- Delivering Commissioning Assurance through Pro-active Stakeholder Alignment
Authors: Sreekanth S. P. , Al Naqbi Sulaiman Ahmed , Ramana Narra Venkata , Khan Aqrar Ahmed , Al Katheeri Nashmi Abdul , Mukkamala Srinivasa Rao , Kowtha Ravi kumar , Kroosh Abdalla Mohammed
Published: November 2015

Projects Handing over to Assets/Operations is always a challenge.To Deliver Commissioning Assurance through stakeholder pro-active Alignment and smooth Handing over of Project to Assets/ Operations, we have identified the Commissioning requirements to embed in FEED Scope of work and developed an Internal Commissioning & Hand over strategy as follows:

At FEED stage of the project, all Commissioning requirments, Start-Up sequence, Performance Test Run requirements & Acceptance criteria are identified and ensured that the same are embedded in EPC scope of work.

At early stage of Project Execution an Internal Commissioning & Hand over strategy is developed by covering Roles and responsibilities of all involved stake holders, Hand over protocol, Inerfaces, Startup sequence, Performance test run requirments and Acceptance criteria.

An agreed hand over procedure/process is developed by covering Operational spares, Final documentation, Punch List dispute resolution mechanism and Warranty Claim Managmenet procedure and aligned all stake holders.
A Holistic Stimulation Approach to Unlock Potential of Horizontal Open Hole Completion in Tight Carbonate: Optimization of Acidizing Treatment and Successful Diversion in Real-Time Using Distributed Temperature Sensing.
Authors: Salah Mohamed , Bereak Ahmed , Gabry Mohamed , Shaheen Tarek , Kewan Mona
Published: November 2015

Abu Roash-D is characterized as a carbonate reservoir in Abu Gharadig field, Western Desert of Egypt. It has a good lateral continuity, contains natural fractures with poor connectivity in addition to formation tightness. To further increase the production from the field, a full development plan for Abu Roash-D carbonate reservoir was initiated with drilling of horizontal wells. The main objectives of drilling such horizontal wells was to develop the tight unconventional reservoirs and increase production by dramatically increasing the contact area with the producing interval, maximizing drainage volume around a well and link the natural fractures network thus, achieving an economically production targets.

The effective placement of sufficient acid volume along the open-hole section of such horizontal wells provides significant challenges in acid diversion due to the high permeability streaks that requires a very effective diversion technique for optimal acid distribution a long the open hole lateral for a successful acid stimulation treatment.

A fiber optic enabled coiled tubing attempts to tackle some of these limitations. This new approach deploys downhole sensors with fiber optic telemetry inside the coiled tubing string provides a real time temperature, pressure and correlated depth measurments. The fiber optic telemetry allows distributed temperature surveys recording for obtaining temperature profiles across the entire wellbore. Monitoring the distributed temperature sensing (DTS) profiles accompined with downhole pressure data interpretation enables real time diagnostic of downhole events between the stimulation stages providing an important aid to further optimize and improve the performance of stimulation treatments.

This paper presents case histories of the first time implementation of horizontal wells in Abu Roash-D tight carbonate reservoir in Egypt's western desert in which fiber optic enabled coiled tubing was utilized to optimize stimulation treatment. The real time monitoring of downhole distributed temperature sensing profiles allowed the identification of both high permeability zones as well as tight zones across the entire openhole lateral. This enabled the operator to take pro-active decision on where to spot diverter or acid, select the best diversion technique and allow for treatment optimization.
Identify the Key Uncertainties Which Influence Production Performance and Recovery by Using Global Analogs
Authors: Lu Xiaoguang , Sun Shaoqing , Jenkins David
Published: November 2015

Limited data is available for a new discovery at the preparatory stage for the plan of development (POD). Uncertainties exist such as the depositional environment of the reservoir and individual sandbody type, reservoir heterogeneities and fluid properties. This paper presents an innovative and unique method for the qualitative and quantitative evaluation of the influences of these uncertainties on production performance and final recovery factor.

The developed methodology enables reservoir engineers and development geologists to conduct uncertainty assessment on production performance and final recovery factors by using a global analogs database and proprietary analytical software tools, including performance forecasting, characterization and attribute cross plotting, etc. The process consists of four steps: (a) selection of the analog reservoirs, (b) performance forecast, (c) uncertainties evaluation, and (d) analysis of key drivers impacting performance and recovery factor. In our case study, Field A is in its POD study stage. Based on available information, reservoir sand in Field A potentially consists of sandbodies of either fluvial channel (FC), distributary channel (DC) or combined fluvial and distributary channels (CFDC). Uncertainty evaluation results indicate that the sandbody of FC, DC and CFDC will produce ultimate recovery factors of 35.9%, 37.9% and 39.7% respectively for the medium-case scenario and 52.4%, 54.3% and 59.2%, respectively for the high-case. The various sandbody types also have a great influence on performances of life-cycle production profile, peak production rate and water-cut variations. Analog analysis of the same sandbody type reveals the impact of three group specific attributes on the ultimate recovery.

Compared with the normal approach of conventional geological modeling and reservoir simulation, the analog solution using the proprietary software tool is an efficient process and provides reasonable results.
Improved Polymer Membranes for Sour Gas Filtration and Separation
Authors: George G. , Bhoria N. , Mittal V.
Published: November 2015

This paper contributes to the interest of natural gas industry. It is well known that a scientist continually faces challenge to purify the natural gas (NG) from impurities such as acid gases (CO2 and H2S). The polymer membrane based gas separation has materialized as a promising field of research. There is a need for stiff backboned polymer membranes that can withstand potential membrane swelling and degradation for a cost effective use of the material and the technology.

The polymer used is thermoplastic elastomers poly(ether-b-amide); popularly known as PEBAX (P) that holds a number of properties that makes it potentially useful membrane materials. Room temperature ionic liquids with high selectivity towards acid gas were selected. The careful selection of cations includes 1-Butyl-3-methylimidazolium and 1-(2-etoxy-ethyl)-3-methylimidazolium whereas anions were selected from BF4, PF6. Subsequent supported ionic liquid membrane systems (SILMs) and SILM-nanocomposites were successfully prepared by incorporating nanofiller. The morphology, structure, and stability of these membrane materials were characterized by various techniques. The polymer has rigid polyamide segments which are spaced with malleable polyether segments. The amide segment delivers the mechanical strength, while the soft ether block contributes to the gas transport capabilities. Polymer SILM allows the freedom to effectively tune the structure-property relationship of polymer and ionic liquid in membranes towards its permeability and selectivity of sour gases. Our research discusses the effect of the incorporation of selective ionic liquids to polymer membranes. In particular, we focus on the structure-property relationship of the polymer and room temperature ionic liquids on the gas separation.

The modulus values decreases on addition of ionic liquid. The flexible polyether phase of the polymer gets plasticized by ionic liquid and thereby the elongation also gets reduced. This polymer's backbone was further strengthened by successfully employing either of two strategies such as molecular chain extension/crosslinking or a bulk modification using nanofiller which can impart enhanced mechanical properties as given in figure 1a.