bluuebunny/crossref_metadata_2025 huggingface dataset:
IT and OT Convergence, or Collision? Managing the Merger for Greenfield LNG
Authors: Garvin Thomas
Published: November 2015

The worlds of information technology (IT) and operational technology (OT) in the Oil & Gas space are often considered worlds apart: different goals, different strategies, and different stakeholders. While there is much focus around the convergence of technologies across these domains in support of process optimization and data exchange, organizational aspects come into play which create a multi-dimensional challenge for major capital projects (MCPs) deploying a wide variety of information systems. This paper discusses the broader spectrum of convergence, and shares insights and lessons learned from delivering complex systems integration programs for world-class Liquefied Natural Gas (LNG) MCPs.
Important Considerations for Reserves Estimation in Unconventional Resource Plays
Authors: AbdelMawla Ahmed , Hegazy Mohamed
Published: November 2015

Unconventional resource plays have recently been traded favorably in Acquisitions and Divestitures "A&D" markets due to view of having lower risk and or better growth prospects compared to conventional resources "Devashish, 2014". For unconventional plays, the reservoir geological boundaries usually extend beyond the limits of the acreage holding. Some of the major uncertainties in the unconventional plays reserves and resources assessment tend to be: the basis of declaration of discovery, the definition of the project boundary (technically and commercially), the categorization of reserves/resources referenced to the degree of uncertainty, and the appropriate methods to estimate the production forecasts and ultimate recovery.

In this paper we present field example from unconventional resource play. The reasons for variations between different reserve estimations for the same asset (based on real case history) are explained, with recommendations for practical considerations. These include using diagnostic techniques of production data to establish production forecasts that satisfy the reasonable certainty criteria required for booking reserves. We will discuss examples for the implementation of the reserves categorization in unconventional resource plays according to the guidelines of SEC and SPE Petroleum Resources Management System "SPE-PRMS". Additionally, some practical rules for the assessment of contingent resources in unconventional plays will be discussed.

It should be noted that reserves categorization in unconventional resource plays is an area that is subject to different interpretations across the industry, resulting in variations in the results of reserves estimation between different estimators. The contribution of this work is a critical discussion on these differences, and how they relate to the uncertainty on production forecasts. It is our expectation that better understanding of the uncertainty leads toward best practices for reserves estimations throughout the industry.
Production Performance of Gas Condensate Reservoirs: Compositional Numerical Model - A Case Study of Hai Thach - Moc Tinh Fields
Authors: Tran T.V. , Ngo A. T. , Hoang H. M. , Tran N. H.
Published: November 2015

The approach focuses on the use of analytical and 3D dynamic compositional numerical models to physically describe the condensate banking phenomenon and to better understand the real deliverability in terms of gas and condensate production. The model is also built to compare the benefits of hydraulic fracturing over the horizontal well in Bien Dong POC development campaign.

In this study, an analysis of pressure transient test data is conducted to investigate the condensate bank radius. Construction of a radial model is used as a benchmark model to compare it to an equivalent Cartesian grid model in term of productivity. The paper is focused on the development of a workflow for the analysis and selection of grid size and methods used in the 3D compositional model. Then the model is used for horizontal and hydraulic fracturing designs.

When the flowing bottomhole pressure falls below dew point, the condensate dropouts in the near wellbore reduce permeability to gas through relative permeability effects; hence the well productivity is reduced significantly. The prediction of gas condensate well production will strongly depend on condensate banking evaluation and modeling. It is important that a model is built to describe the condensate banking phenomenon accurately to avoid over-estimating well performance. It is shown that an integrated model which incorporates Generalized Pseudo Pressure (GPP) and Local Grid Refinement (LGRs) can reproduce almost exactly with the benchmark model. The presented procedure and analysis can serve as a guideline for full field gas condensate reservoir modeling. The study also suggests that un-fractured horizontal well is not attractive compared to hydraulic fractured vertical well. Fractured half-length optimization design should be based on economic criterion.

The study addresses the complexity of gas condensate behavior around the near wellbore region. The workflow of building an accurate 3D compositional model allows Bien Dong POC to have a reliable resource in reservoir development and management plans.

The applicability of this work is confirmed by actual field case study in offshore Vietnam. It contributes to the knowledge of performance of gas condensate reservoirs and supports representative modeling of detailed model and recovery processes.
Analogue Modelling of Shah Structure in Abu Dhabi; Mode and Structural Evolution
Authors: Koyi Hemin , Sirat Manhal , Morad Daniel
Published: November 2015

Three-dimensional seismic data have been used to construct a series of scaled analogue models simulating the structural evolution of the Shah hydrocarbon Field. Models consisted of a set of layers of loose sand on two basal plates whose contact simulated a basement fault. Depositional history of the Shah structure was simulated in the model by producing syn-kinematic deposition and erosion. Deformation of the model was achieved by moving one of the basement plates in a way that it initiated an oblique slip along the basement fault. This oblique movement induced both a strike slip movement in and shortening of the cover sand layers, which resulted in formation of an open anticline (box fold) along the strike of the fault similar to the Shah structure.

The 3D seismic mapping of the Shah hydrocarbon Field reveals carbonates dominating lithological units from the Pre Khuff Fm (Permian) to the Dammam Fm (Eocene). A major unconformity in the stratigraphy indicates uplift, exhumation and erosion at Simsima level (U. Cretaceous) with onlapping of the younger units (Eocene-Miocene Formations). The Shah structure is an open SW-NE striking anticline, which changes symmetry along strike; asymmetric in the SW, more symmetric in the middle, and asymmetric open anticline in the NE. Model results indicate that the structure is a basement related cover anticline formed due to the oblique movement along a basement fault, which was reactivated during the obduction of Semail Ophiolite and later collision of Arabia with Iranian plate. These results show that this anticline formed without the need for a shortening component perpendicular to the strike of the structure. An oblique slip along a basement fault, with a relatively small degree of shortening could equally well result in the formation of such open and low-amplitude anticline.

The modelling results presented here provides an alternative scenario for the formation of Shah structure (low-amplitude, and open) and addresses some of the key questions about its structural constraints (e.g. geometry, timing and evolution history) by linking it with basement structures. Our modelling results are of high significance for understanding entrapment mechanism, migration pathways, and fracture development. This newly proposed mechanism impacts the exploration and development of the Onshore Fields in Abu Dhabi, at the vicinity of Shah Structure.
Organic/Inorganic Deposition in Oil Producing Wells from Carbonate Reservoirs: Mechanisms, Removal and Mitigation
Authors: Al-Taq Ali A. , Muhaish Salah A. , Nakhli Maithem M. , Alrustum Abdullah A.
Published: November 2015

Several wells in a carbonate reservoir have experienced significant reduction in their oil productivity. Bailer samples collected from these wells showed that they were damaged with organic/inorganic deposition. Analysis of the collected material showed that the organic deposits consisted of asphaltene and associated paraffins while the inorganic deposits were mainly calcite with ankerite, anhydrite and small amounts of quartz and halite.

The formation of calcium carbonate scale is anticipated to occur due to CO2 degassing during production. In addition, these wells produce commingled oil from two carbonate reservoirs which allow their formation waters to mix together; therefore, scaling tendency prediction showed a positive saturation index for calcium carbonate. The sulfate scale in the form of anhydrite is anticipated to be formed due to mixing of high sulfate source (seawater), used to maintain reservoir pressure, with a calcium rich source (formation water).

The colloidal instability index from SARA analysis indicated that the reservoir oil in this field has a moderate instability to potentially precipitate asphaltenes. Additionally, the interaction of low pH scale inhibitor with the formation oil and presence of charged particles such as calcite will destabilize asphaltenes in oil.

Two techniques were examined toward dissolving the organic/inorganic deposition including a two-stage and a single-stage method. The two-stage method involves the use of solvent preflush to remove the organic coating material from the whole deposits followed with the use of HCl acid to remove the remaining inorganic deposits. An emulsified HCl acid/solvent is used in the single stage method to remove the whole deposits.

The paper discusses different analytical techniques used to identify the nature of the damaging material, mechanism of organic/inorganic deposition, and the optimization of dissolver/solvent systems to remove formation damage and restore productivity of damaged wells. It also assesses and optimizes the current used scale inhibitor squeeze (SIS) treatment program.
Cost and Weight Reduction by Choosing Aluminium for Offshore Structures
Authors: Jongejan Maarten , Mackintosh Amanda , de Kluijver Dick
Published: November 2015

As weight issues become increasingly apparent within the offshore construction industry, aluminium is gaining attention. By constructing large offshore platform/vessel parts from aluminium, the reduction in weight is significant: up to 60% less than steel. Replacing steel construction with full aluminium structures is not entirely feasible; thus the path forward lies in working with aluminium and steel together. Fabricating with aluminium requires a different approach starting with the earliest stages of the project. Only with innovative, out-of-the-box thinking can we use the attributes of aluminium to the fullest extent. Aluminium has valuable benefits; particularly in the harsh and highly corrosive seawater environment, for example, aluminium alloys used in the offshore industry corrode 100 times slower than steel, thus requiring little to no maintenance, resulting in a durable structure with a very low cost of ownership.

In general, an aluminium construction always outlives the platform. Despite all those great benefits, there are quite a number of preconceptions around using this material in construction projects; such as its behaviour in a fire, the complexity of welding, and its price. In this paper, we will address these assumptions and clear up popular misconceptions.
Inversion of Wireline Formation Tester Data to Estimate In-Situ Relative Permeability and Capillary Pressure
Authors: Cig Koksal , Ayan Cosan , Kristensen Morten , Liang Lin , El Battawy Ahmed , Elshahawi Hani , Ramaswami Shyam , Mackay Eric
Published: November 2015

Relative permeability and capillary pressure curves are crucial inputs for a reservoir description. However, measuring these quantities on core samples in the laboratory is an extensive and time-consuming process. Wireline Formation Tester (WFT) logging is routinely applied in field operations for reservoir evaluation purposes. Often a historical record of WFT data exists for a field which can be re-interpreted, and since this interpretation takes days, rather than months to years in the case of core analysis, we propose in this paper to revisit the acquired WFT data with the purpose of estimating multiphase flow properties.

WFT logging is generally conducted in an open hole environment. By the time of logging, the near-wellbore region has been exposed to mud filtrate invasion. In the case of immiscible mud filtrate and formation fluid the invasion resembles a small scale water-flood process. During WFT sampling the mud filtrate is first cleaned and formation fluid subsequently sampled in a multiphase flow environment while measuring bottom-hole pressures and water-cuts. As shown in previous papers (Cig et al., 2014, 2015), the measured WFT data can be utilized in an inversion workflow to estimate relative permeabilities by combining a forward model of the cleanup process with an optimization engine.

The proposed methodology starts with an open hole log interpretation which provides reservoir properties including a saturation distribution. The filtrate invasion is represented as accurate as possible from the open hole logs and drilling reports. WFT tool geometry and its internal tool storage and fluid segregation effects are incorporated into the modeling. A numerical forward model is then simulated within an optimization workflow where relative permeabilities, capillary pressures, damage skin, and depth of mud filtrate invasion are estimated by minimizing a misfit function between measured and modeled bottom-hole pressures and water-cuts. Industry accepted parameterization techniques are used for the relative permeability and capillary pressure curves. Initial parameter estimates are provided from the interpretations of the open hole logs, such as resistivity, dielectric, nuclear magnetic resonance, as well as from pressure transient analysis.

Previously we have studied WFT data from a 3D radial probe (3DRP) and a dual packer (DP) (Cig et al., 2014, 2015). The proposed methodology was also validated with synthetic datasets in the same papers. In this paper we extend the methodology to a single probe (SP) inlet and to joint inversion of both capillary pressure and relative permeability curves. We demonstrate the methodology using field data from a Central Asian clastic reservoir. Interpretation of multiphase flow properties from WFT data represents a valuable complement to core measurements and will help to condition reservoir models for more reliable forecasting.
Stimulating The Giants: Carbonate Acid Stimulation Design in Horizontal Open Hole and ICD Completions
Authors: Clemens C. , Kutty S. M. , Zidan M. F. , Tajuddin M. S.
Published: November 2015

A stimulation optimization study was recently conducted to design the acid recipes and execution programs for a new carbonate field in Abu Dhabi. The following paper outlines lessons learned and technical considerations that can improve the stimulation design of carbonate reservoirs. This particular field has a variety of extended horizontal completions ranging from open hole drains to liners with inflow control devices (ICDs). The following testing format can lead to immediate cost savings and long-term production increases in both green and brown fields. The Reservoir and Operation teams leveraged their expertise to place science firmly behind this important aspect of bringing a new field online. By being exact about the recipe testing procedure, the team made technical improvements to the existing recipes while also lowering the cost of stimulation.
Incorporation of Climate Change Mitigation and Adaptation in Environmental Impact Assessment
Authors: Reddy Vijaya Bhasker , Al Bisher Khalid , Monaghan David
Published: November 2015

Major developmental activities, such as power generation, mining, manufacturing, oil and gas exploration, transportation and infrastructure projects, result in large scale release of Green House Gases (GHG) (i.e. carbon dioxide (CO2), methane (CH4), Sulphur Hexafluoride (SF6) and nitrous oxide (N2O)). Release of these gases affect climate change indirectly and pose a serious challenge to global development and project planning due to uncertainty of the climate change impacts.

Traditionally, projects are assessed for their potential impact on the environment. Often climate change mitigation and adaptation aspects have not been considered during the project life cycle impact assessment.

Reducing GHG emissions continues to be one of the main policy drivers to meet the Kyoto Protocol targets and commitments under various climate change conventions. Current Environmental Impact Assessment (EIA) methodology focuses on conventional pollutant discharges. Climate change due to GHG emissions are not considered as a pollution issue. This paper explores the opportunities and challenges in integrating climate change as a consideration that can be embedded in the EIA process.
After 14 years of Water Flooding a Giant Reservoir in North Kuwait: Lessons Learnt, Experiences Gained and Way Forward
Authors: Chetri Hom , Al-Quene Amna , Jamal Mariam , Al-Zaabi Hamad
Published: November 2015

The Sabiriyah Mauddud limestone is a super-giant depletion drive oil reservoir in North Kuwait. It is undergoing massive development efforts, with a planned enhancement in oil production through phased water flood development since 2000.

The Phase1 development addresses the crestal area (60 km2) of the structure, which was the focus for development efforts in the past. 14 years of dynamic performance from producers and injectors located in the Ph1 area enhanced the understanding of the reservoir dynamics. Time lapsed monitoring of static reservoir pressures at key wells during the ongoing water flood, coupled with isochronal Pressure surveys during reservoir shut-downs and RFT data from newly drilled wells in the area during the post injection period, helped to confirm the pressure connectivity across the reservoir and the water flood response. As all the wells are on ESP, the live data on Pump-intake Pressures provided insights into response behavior. Production tests gave valuable insights into the well performance, specially water cut build-up and reservoir architecture. Integration of the dynamic data with Production logs & FMIs led to the identification of speed zones with high permeability. One of the limitations of the pattern water flood with a combination of vertical injectors & vertical producers perforated across the whole hydrodynamic unit was a quick water breakthrough via the high perm speed zones and re-circulation of the injected water, as evident from tracer surveys and PLT data. A comprehensive review and updated performance analysis led to the need of re-developing the reservoir with a paradigm shift using a combination of Horizontal injectors drilled & completed at bottom of the hydraulic unit and the horizontal producers drilled/ completed at upper part so that the water breakthrough is delayed and better sweep is achieved. A conformance plan has been taken up so as to switch over to the new strategy.

The Phase2 development consists of all remaining peripheral acreage (250 km2), with immense reservoir rock & fluid uncertainties, leading to the identification of reservoir segments for re-appraisal through drilling & testing of new wells. Re-appraisal work, along with enhanced fluid description, led to the conclusion that a large segment within the Ph2 area, originally considered as a regime of light oil - turned out to be viscous oil with a high pressure ramp. In addition to helping the ongoing Full field dynamic modeling and development planning for this giant reservoir, this also led to the initiation of a peripheral Water flood with vertical wells initially, and switching over to Non-Conventional Wells in the poorer Ph2 area.

This paper documents the case history of Waterflood management in a super-giant carbonate reservoir and the challenges that had to be met with a quick re-adjustment to the development plan as necessitated during the ongoing implementation & evaluation.
Reduced Polymer Loading, High Temperature Fracturing Fluids using Nano-crosslinkers
Authors: Liang Feng , Al-Muntasheri Ghaithan , Ow Hooisweng , Cox Jason
Published: November 2015

In the quest to discover more natural gas resources, considerable attention has been devoted to finding and extracting gas locked within tight formations with permeability in the nanoto microdarcy range. The main challenges associated with working in such formations are the intrinsically high temperature and high pressure bottom hole conditions. For formations with bottom hole temperatures around 350-400°F, traditional hydraulic fracturing fluids that use crosslinked polysaccharide gels, such as guar and its derivatives, are not suitable because of significant polymer breakdown in this temperature range. Fracturing fluids that can work at these temperatures require thermally stable synthetic polymers such as acrylamide-based polymers. However, such polymers have to be employed at very high concentrations in order to suspend proppants. The high polymer concentrations make it very difficult to completely degrade at the end of a fracturing operation. As a consequence, formation damage by polymer residue can block formation conductivity to gas flow.

This paper addresses the shortcomings of the current state-of-the-art high temperature fracturing fluids, and focuses on developing a less damaging, high-temperature stable fluid that can be used at temperatures up to 400°F. A laboratory study was conducted with this novel system which is comprised of a synthetic acrylamide-based copolymer gelling agent and is capable of being crosslinked with a nano-sized particulate crosslinker (nano-crosslinker). The laboratory data has demonstrated that the temperature stability of the crosslinked fluid is much better than a similar fluid lacking the nano-crosslinker. The nano-crosslinker allows the novel fluid system to operate at significantly lower polymer concentrations (25 to 45 pptg) when compared to current commercial fluid systems (50 to 87 pptg) designed for temperatures from 350°F to 400°F. This paper presents results from rheological studies which demonstrate superior crosslinking performance and thermal stability in this temperature range. This fracturing fluid system has sufficient proppant carrying viscosity, and allows for efficient cleanup using an oxidizer-type breaker. Low polymer loading and little or no polymer residue are anticipated to facilitate efficient cleanup, reduced formation damage, better fluid conductivity and enhanced production rates. Laboratory results from proppant-pack regained conductivity tests are also presented.
Implementing Data Management Solutions within a Massive Greenfield Start up –A Case History, Onshore UAE
Authors: Uniyal Parashu , Al Blooshi Ahmed , Al Hammadi Ali
Published: November 2015

Startup green-field assets go through exponential growth of structured data and unstructured documents and records in core E&P domains. With simultaneous rapid evolution on infrastructure, information security and compliance fronts, this poses considerable challenges in supporting end-user beneficiaries—from real-time drilling operations through to operational improvement and better-informed and auditable decision-making. The data management function needs to be far more adaptive, resilient and agile than its counterpart in matured assets.

This paper describes the Al Hosn Gas journey, over the past few years of existence, down the critical path of E&P data management. Transition from users' local storage to network shared drive-based file management on one hand, and distributed architectures for applications' project data management on the other, constitute important milestones. A hybrid approach to ensuring data availability and optimum throughputs, while complying with fast evolving information security/protection and governance norms, has provided a robust driving mechanism. We discuss the Al Hosn Gas model of integrating "gold" standard data, generated through applications' value chain, to ADNOC’s national data repository.

Challenging though it can be, efficient & effective implementation of data management best practices in a green-field asset environment, as early as possible and as widespread as practical, can result in enormous value addition to end-users & management alike. High degrees of adaptability and resilience of architectures and accompanying processes have enabled Al Hosn Gas to foster a robust and agile data management paradigm.
Production Performance of Horizontal Gas Wells Associated with Non-Darcy Turbulent Flow
Authors: Lu Jing , Li Sima , Rahman Md Motiur
Published: November 2015

In the petroleum literature, non-Darcy flow is assumed to be a near wellbore phenomenon, consequently a gas reservoir could be divided into Darcy’s flow domain and non-Darcy’s flow domain. Assume only radial flow occurs in the near wellbore non-Darcy’s flow domain, and assume the radius of this domain is integer multiple of wellbore radius, Lu et al. (2011) proposed binomial deliverability equations for partially penetrating vertical gas wells and horizontal gas wells. By solving a set of simultaneous equations with respect to non-Darcy’s flow domain rn and flow rate at standard condictions Qsc, this paper presents new binomial deliverability equations for horizontal gas wells, which can account for the advantages of horizontal gas wells where non-darcy effect is less pronounced than that in vertical gas wells. The calculation results show that non-Darcy flow domain radius is smaller than 20 times wellbore radius, which further proves turbulent effect only occurs in the vicinity of wellbore. The calculation results also show that the production rate loss of horizontal wells caused by the turbulent flow is small.
Numerical Simulation of Natural Gas Flow in Anisotropic Shale Reservoirs
Authors: Negara Ardiansyah , Salama Amgad , Sun Shuyu , Elgassier Mokhtar , Wu Yu-Shu
Published: November 2015

Shale gas resources have received great attention in the last decade due to the decline of the conventional gas resources. Unlike conventional gas reservoirs, the gas flow in shale formations involves complex processes with many mechanisms such as Knudsen diffusion, slip flow (Klinkenberg effect), gas adsorption and desorption, strong rock-fluid interaction, etc. Shale formations are characterized by the tiny porosity and extremely low-permeability such that the Darcy equation may no longer be valid. Therefore, the Darcy equation needs to be revised through the permeability factor by introducing the apparent permeability. With respect to the rock formations, several studies have shown the existence of anisotropy in shale reservoirs, which is an essential feature that has been established as a consequence of the different geological processes over long period of time. Anisotropy of hydraulic properties of subsurface rock formations plays a significant role in dictating the direction of fluid flow. The direction of fluid flow is not only dependent on the direction of pressure gradient, but it also depends on the principal directions of anisotropy. Therefore, it is very important to take into consideration anisotropy when modeling gas flow in shale reservoirs. In this work, the gas flow mechanisms as mentioned earlier together with anisotropy are incorporated into the dual-porosity dual-permeability model through the full-tensor apparent permeability. We employ the multipoint flux approximation (MPFA) method to handle the full-tensor apparent permeability. We combine MPFA method with the experimenting pressure field approach, i.e., a newly developed technique that enables us to solve the global problem by breaking it into a multitude of local problems. This approach generates a set of predefined pressure fields in the solution domain in such a way that the undetermined coefficients are calculated from these pressure fields. In other words, the matrix of coefficients is constructed automatically within the solver. We ran a numerical model with different scenarios of anisotropy orientations and compared the results with the isotropic model in order to show the differences between them. We investigated the effect of anisotropy in both the matrix and fracture systems. The numerical results show anisotropy plays a crucial role in dictating the pressure fields as well as the gas flow streamlines. Furthermore, the numerical results clearly show the effects of anisotropy on the production rate and cumulative production. Incorporating anisotropy together with gas flow mechanisms in shale formations into the reservoir model is essential particularly for predicting maximum gas production from shale reservoirs.
Operation Readiness Plan Management Process for Successful EPC Project Execution and Start Up
Authors: Das Anil Kumar , Al Naqbi Sulaiman , Kumar Ravi , Walid Mohammed , Bhasker Bhasker , Khan Aqrar
Published: November 2015

Abstract (Category: Projects Engineering and Management: SESSION 40: Commissioning, Start-Up and Handover Challenges)

Challenges during transition of Project to Operations

➢ Timely availability of spares (Commissioning, Insurance and Operating). ➢ Updating of existing operating Manual and procedures (Brownfield) and new Operating Manuals and procedures (Greenfield). ➢ Manpower availability/required training for operation & maintenance of new facilities. ➢ Asset registration/Maintenance Plans to be completed /finalized. ➢ Maintenance contracts for equipment to be in place. ➢ Assurance for fulfilment of all Integrity requirements.
High Grade Steel Pipeline for Long Distance Natural Gas Projects
Authors: Cheldi Tiziana , Castano Michele , Spinelli Carlo Maria
Published: November 2015

Natural gas will play the role, in the years to come, of the main fossil fuel, even the energetic scenario is moving to the renewable sources as an alternative for the far future; natural gas will act as a "bridge" to guarantee the transition to the "green energy" from the actual one [0].

As a matter of fact the era of easy gas is "terminated", now there is the need of large investments to connect big gas reservoirs located in far and sometimes stranded locations. To have access to these reservoirs, from the logistic and economical point of view of the exploitation, the cost for gathering natural gas has to be reduced dramatically. The cost cut has to affect not only the construction but also the operational duties. So any new solution has to be properly checked, before to be put in place, to assure it must be as reliable as the actual currently used. From the mid of the 90' it has been shown as the adoption of very high pressure for the transportation of large amount of natural gas it's the easiest solution to be used; the main reason of that it's because it's based on the enhancement of current technologies used for the manufacturing of the material, for the construction and maintenance of the gas pipeline; it doesn't need any break through leap that may create a divide with the actual way or working.

The material proposed is C steel with higher strength in term of yield and tensile stress. Material as carbon steel above API 5L X80 and X90 and in some cases also X100 have been considered for this application. The paper is aimed to highlight the topic need to better understand the use of API 5L X80 C steel for pipeline (UOE & Spiral welded) to be used for mild/harsh scenarios in onshore pipeline laying.

Eni committed its interest on pipeline high strength steels by combining experimental researches and theoretic studies on structural integrity & reliability [0].

The scope is to address the design phase towards quantitative safety targets for which the reliability level specified by designer and desired by operator is pursued. X80 pipeline steel had so far not been used mainly because the lower steels grade were suitable for any of the previous applications, and also because of the predominant attitude in O&G sector to adopt new solutions is conservative; furthermore the lack of experience on "in field application", it's another reason to "freeze" the evolution process.

This project was aimed to fill these gaps through an integrated "full scale and realistic long term tests" approach. The innovation embedded in this R&D project is to have an overall cycle approach, involving the analysis of aspect related to the engineering phase, enhancement in the construction methods, and last but not the least also the maintenance and daily operational duties.
Sulfur Recovery Unit - Integrity Operating Window & the Main Issues
Authors: Adamou Adib Soufiane
Published: November 2015

ADGAS operates three Sulfur Recovery Units (SRUs), commonly referred to as sulfur plants, for several years, which, various issues related to the integrity impacted the operational reliability of these units. In an effort to reduce emissions and comply with environmental requirements, ADGAS has developed new modules to do Super Claus.

This paper presents the Integrity Operating Window for these (SRUs). It identifies and discusses the corrosion mechanisms and fouling that may occur in SRUs in the main section in the sulfur plants, and discusses methods of prevention, including guidelines for start-up and shutdown of equipment.

A general discussion of materials selection for SRUs is also presented. Key process parameters are identified which should be routinely monitored and controlled within designated limits. These key process parameters and their respective limits should serve to define the appropriate operating window for control of corrosion and fouling in SRU and as a basis for management of change considerations.

A specific case studies, related to Sulfur Recovery Units past operating experience is also included. Mainly, ADGAS faced many integrity issues related to the Waste Heat Boiler, Main Combustion Chamber refractory, sulfur accumulation, weld joints sulfur contamination and sulfur solidification in the sulfur tank safety devices.

Different recommendations will be addressed in order to avoid SRU unplanned shutdown based on ADGAS experience with operation the three SRUs.
Palaeogeographic Reconstruction of a Tide-Dominated Oolite Shoal Complex in the Lower Arab Formation, Onshore UAE
Authors: Lawrence David A. , Hollis Cathy , Green David , de Perière Matthieu Deville , Al Darmaki Fatima , Bouzida Yasmina
Published: November 2015

The Late Jurassic Arab Formation is being developed in a major gas accumulation located onshore southern UAE. The lower Arab Formation consists of wackestones to mudstones of mid ramp to basinal setting overlain by foreshoal and oolitic grainstone shoal deposits. Despite the number of well penetrations, several published models have been proposed for the palaeogeographic evolution of the shoal complex.

The grainstone-dominated interval comprises skeletal and ooid-rich wackestones and packstones grading upwards into oolitic grainstones interpreted as the result of progradation of foreshoal to ooid shoal environments. A key element to understanding reservoir architecture has been the integration of core descriptions with borehole image logs, permitting recognition and re-orientation of the main bounding surfaces and cross-bedding sets. Existing depositional models for grainstone shoals are highly schematic and not useful for defining reservoir architecture.

Two key surfaces constrain correlation and reservoir architecture: a basal hardground typified by dolomitised burrows and an upper erosion surface which terminates grainstone deposition. Shoal initiation was in the southwest of the study area with progradation of bioturbated foreshoal deposits with isolated planar cross-sets. Tidal reversals become more frequent upwards, with deposition mainly in offshore flood-oriented ooid sand ridges.

The main part of the grainstone interval is dominated by a stacked parabolic sand shoal complex comprising cross-bedded oolitic and skeletal grainstones. Initial primary macroporosity in this facies association is pervasively occluded by calcite cements. Behind the shoal complex, planar laminated oolitic grainstones accumulated in flood-tidal deltas in a broad lagoon. Progressive infilling of the lagoon by sediment supplied from the shoal resulted in basinward (northeasterly) shifting of the shoreline and development of linear beach ridges. Bioturbated to massive grainstones capping shoal complexes are clean and only patchily cemented retaining a well-connected primary macropore network.

Geometries, scales of cyclicity and facies distributions indicate analogs to modern tidally-influenced ooid ridges and parabolic bars of the Bahamian system.
Chemical Solutions to Handle Viscosified Back Produced Water in Case of Polymer Flooding
Authors: Rambeau Odile , Alves Marie-Hélène , Loriau Matthieu , Molinier Valérie , Passade-Boupat Nicolas , Lebas Geneviève
Published: November 2015

Polymer flooding is used as a secondary or tertiary recovery mechanism to enhance oil production and increase oil reserves. In such situations, part of the injected polymer will be back produced at the topsides at different ratios depending on the injection mode and along field life. The side effects of polymer flooding on the topsides process chain are identified as manageable trouble regarding oil/water separation, and major issues at the water treatment stage.

The presence of polymer in the produced water increases the viscosity and the severity of the emulsion. Literature dealing with viscosified water has already highlighted decreases of efficiency of water treatment technologies such as hydrocyclones, flotation, generating inadequate water quality for produced water reinjection (PWRI). A common way to optimize flotation on field is to inject additives. But the polymer impedes the action of conventional chemicals used in O&G Production.

Chemicals usually help to improve the water quality, regarding constraints of PWRI. This paper focuses on chemical approach along the separation and water treatment chain in case of back produced polymer.

For this study, we used HPAM, a high molecular weight polyacrylamide commonly used in EOR. Previous works on conventional water treatment additives have shown a high consumption of chemical to clarify viscosified water, which is not economically practicable.

Therefore, we proposed to explore another approach, first taking care of water quality upstream at the separation stage, then pursuing on chemical optimization at the water treatment stage.

At first, a lab methodology for separation studies was developed to generate a thin emulsion with controlled degradation of the polymer, simulating the characteristics of the back produced viscosified water on field. A screening of demulsifiers was carried out on emulsion containing 10% oil and synthetic polymer back produced water (up to 500 ppm HPAM). These tests have shown that water quality can be improved at the separation stage, at conventional dosage at lab scale. The remaining oil in water for 10% initial oil, depending on the residence time, is maintained in the range of few tens to few hundreds ppm. Water treatment optimization reference case was then based on few hundreds ppm of remaining oil.

For water treatment studies, oil in water emulsions were prepared by mixing oil with synthetic or real viscosified water (up to 500 ppm HPAM) with an ultra-turrax homogenizer. Different types of clarifiers ranging from 50 to 100 ppm were evaluated. These tests have shown that water quality can be improved using a combination of adequate additives. These bench lab results were confirmed on a lab conventional technology, and could be further evaluated in field trials for an integrated solution.
Drill Pipe Grades Improvements and Industry Standards Evolutions to Address Increasing H2S Challenges: a Decade in Review
Authors: Flores Vincent
Published: November 2015

Hydrogen Sulfide (H2S) can interact with steel tubular, and through the unfavorable combination of different factors can initiate a crack in the material, which could propagate until failure. This phenomenon can occur when stresses are largely below the material yield strength. The combination of tubular failures due to Sulfide Stress Cracking (SSC) and the rising HSE concerns when dealing with sour gas has led the industry to develop new drill pipe grades with enhanced resistance to SSC.

Material selection for drill pipe in a sour environment is significantly unclear, mainly due to the absence of existing international standard specifically related to H2S resistant drill pipe. Nonetheless, Canada has led the way by publishing their "Industry Recommended Practices" (IRP) Volume 1 in 2004; the standard was created to insist on people safety, and provide specification and guidelines to manufacturers on material properties, quality control, testing and inspection of drilling products intended to be used in critical sour wells.

Sour Service Drill Pipe as defined in the IRP has been used for over a decade in Canada, as well as in other parts of the world. Manufacturers have also developed a variety of other proprietary Sour Service grades of drill pipe and BHA. This paper proposes a review of different field cases in the Middle East and Asia, as well as an outlook of the different practices for material selection and qualification guidelines which have emerged since the past 10 years.

With the current increasing demand of domestic gas in different part of the world, some highly sour oil and gas reservoirs are being explored with H2S contents beyond what could have been imagined a decade ago. To explore, appraise and eventually develop such fields, most of the time combined with complex well profiles or deeper reservoirs, significant technical challenges need to be addressed regarding drill pipe integrity and operations safety. This paper proposes a non-exhaustive review of the newest emerging industry trends as far as international standard guidance, regional normative initiatives, and new steel developments.
Gas Injection EOR Screening by Laboratory Experiment and Sector Modeling in Carbonate Reservoir
Authors: Kumar Jitendra , Yammahi Fatmah S. , Nakashima Toshinori
Published: November 2015

Hydrocarbon gas injection projects are undertaken in order to maintain reservoir pressure, produce oil through swelling and reduce residual oil saturation by decreasing the interfacial tension (IFT). Along with local displacement efficiency, macroscopic sweep efficiency plays a dominant role in the success of gas injection projects, as recovery from the field depends strongly on reservoir geology and petrophysical properties.

In this paper, a procedure to screen the best injectant for implementation of a successful gas injection pilot project is discussed. To determine the microscopic sweep efficiency, PVT experiments and coreflood tests are conducted. First, minimum miscibility pressure (MMP), oil solubility and IFT values are measured through PVT experiments, which is followed by unsteady-state coreflood experiments on 200 cm long cores to evaluate the sweep efficiency at miscible and immiscible conditions. Data from the experiments are used to evaluate oil recovery in a sector model extracted from the full field model. The sector model analysis for different injection scenarios provides sweep efficiency and guidelines for the implementation of the gas injection pilot project.

The coreflood experiments show improvement in recovery in immiscible conditions due to oil swelling and reduction in IFT, while higher recovery is achieved in miscible conditions due to multiple-contact miscibility. Evaluation of the macroscopic sweep efficiency in the sector model highlights the issue of gas override, and suggests improving the sweep by gas enrichment, as well as water-alternating-gas injection (WAG).
The Successful Implementation of a "Center Of Excellence" for the Upstream Oil Sector in Kuwait
Authors: Al-Zeabot Nadia , Thomas Cyril
Published: November 2015

Kuwait Petroleum Corporation (KPC) directed its Upstream subsidiaries to collaboratively work towards an integrated 2030 strategy. One of the key elements to achieving the 2030 strategic objectives was to collaborate and share expertise to resolve technical challenges currently facing the upstream entities. As a result, the Center of Excellence (CoE) was successfully implemented to leverage the diverse expertise of technical talent across the three upstream entities of Kuwait Oil Company (KOC), Kuwait Gulf Oil Company (KGOC) and Kuwait Foreign Petroleum Exploration Company (KUFPEC). CoE Discipline teams comprising of experts in strategically important technical disciplines created significant business value through sharing of knowledge, lessons learned, and experiences, around specific technical challenges.

To embed the CoE as a way of working, change management was identified as a key enabler. Various interventions including organization-wide communications, focus on value creation, incentives, and capability development were implemented to build commitment and manage different stakeholder groups. Specific messages were deployed through high impact communication tools to build wider stakeholder support. The Upstream leadership provided sponsorship and visible support to drive implementation and ensure that value from CoE is recognized. This multi-pronged approach helped embed CoE within the inherent fabric of upstream entities, enabling it to deliver business value.
Wasia Unconventional Oil Exploration Potential in Western Onshore Abu Dhabi
Authors: Taher Ahmed , Al Zaabi Mohamed R.
Published: November 2015

The Wasia unconventional oil potential in west onshore Abu Dhabi is comprised of Mauddud, Shilaif and Tuwayil formations.

The Mauddud potentiality is a result of the downward oil migration from the mature Shilaif Kitchen. The high maturity of Lower Shilaif creates a fracture network that facilitates the primary migration downward into the Mauddud formation. This resulted in filling the Mauddud formation below the Shilaif kitchen and possibly the surrounding areas. Mauddud oil accumulation in the basin was supported by the presence of high hydrocarbon shows while drilling and high hydrocarbon saturation in the interpreted logs.

In the Shilaif source rock, there are three distinct intervals that have potential for shale oil exploration activities in Abu Dhabi. The Lower Shilaif has the highest maturity values and the highest recorded porosity with a very low permeability, while the Upper Shilaif potential represent the thickest part and is expected to have higher permeability values as a result of the presence of lower argillaceous content.

The Upper Tuwayil is comprised of shale sediments that are intercalated with Sandstone streaks. The Sandstone was developed as isolated but laterally extensive sand bodies that are separated by the shale layers. Tuwayil sandstone may represent an unconventional tight oil potential similar to that found in many other basins.