bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimized Field Development of an Offshore Carbonate Reservoir in Saudi Arabia
Authors: Dismuke Carl T. , Jokhio Sarfraz A. , Mubarak Hassan K. , Shuaibi Anas A. 
Published: July 2010

Abstract
A relatively large carbonate reservoir located offshore Saudi Arabia was developed over the last several years to augment production capacity. The objective was to raise the Field-A oil production capacity by an additional 25% to help offset downtime occurring on existing production platforms due to workover and facilities upgrading operations. In this paper, the development project scope, implementation, simulation, use of technology and drilling activities that resulted in a successful implementation of the development plan for the Field-A Reservoir-4, as well as the initial results, will be discussed.
The development was placed on a fast implementation schedule and was carried out during a high oil demand period (2006-2009) that placed large constraints on delivery of new equipment and platforms. The production increment was successfully brought onstream within a 3-year timeframe. The development plan included the installation of three platforms for both oil production wells and power water injectors as well as several sidetracks to add sustainable production capacity. Key wells were equipped with permanent downhole monitoring systems to monitor reservoir pressure performance in real time and the newly drilled producers were completed with electric submersible pump (ESP) lift systems. In addition, the first application in Saudi Aramco of a distributed temperature sensor (DTS) system was deployed in an injector to obtain real time flow profiles along the wellbore section.
The overall development project utilized a number of existing assets to minimize the development cost and trial testing of the innovative applications, such as using existing wells for on-platform water injection that consists of a water supply and an injection well combination while both located on the same platform, and an inverted ESP assisted water injection.
Reservoir simulation studies were used to optimize the wellbore placement and indicated the oil production plateau could be sustained for an extended period.
Using Inter-Volume Similarity Measures as a QC Tool for Seismic Data Processing
Authors: Dossary Saleh A. , Al Garni Khalid , Cunningham George , Al Saad Riyadh 
Published: July 2010

Abstract
Five seismic attributes are proposed to efficiently compare seismic volumes. Two attributes are derived directly from the input datasets, three are derived from a cross correlation of the datasets. All attributes are calculated in a time-sliding window.
The proposed method can be used to verify that consistent phase, e.g. between marine and land datasets, has been used or how attributes such as phase, amplitude or time have changed during a processing workflow. We show the effectiveness of our method by applying it on synthetic and a real datasets.
A Case Application of Geostatistical Inversion of 3D Seismic and Well Data for Enhanced 3D Reservoir Property Modelling
Authors: Udofia Abasiubong , Olotu Sam , Onyekonwu Mike O. 
Published: July 2010

Abstract
A major challenge in reservoir property modelling is integrating the resolution obtained in well logs and the lateral reach of seismic data to obtain a representative model. The seismic data and well logs are recorded as independent pieces of data, each giving subsurface information with different attributes. Recently, solutions to this challenge have emerged in a number of ways. In this case study, implementation was based on a Stochastic Simulation procedure that populated the inter well space with reservoir properties directly linked to 3D seismic and well data. Basic construction principles were geostatistical, though different from conventional geostatistical practices in the sense that in addition to honouring the available well log data, the simulation was conditioned to fully honour the existing seismic data between the wells.
Converting petrophysical properties into acoustic properties that are related to seismic attributes required detailed univariate and multivariate analysis of reservoir properties and acoustic impedance relationships and geostatistical analysis of rock properties at the well log scale.
This approach provided the petrophysical properties in the inter well volume from the absolute acoustic impedance volume. The acoustic impedance volume was derived from geostatistical inversion of the 3D seismic volume and using the vertically detailed impedance realisations as secondary data, and the well porosity as hard data a sequential Gaussian cosimulation was carried out for generation of the porosity models. 3D permeability model was also built from the mean porosity cube utilizing a regression equation
The case study demonstrates the robustness of this approach. A lateral prediction of petrophysical properties was carried out for the reservoir sands in two Niger Delta fields and the resulting acoustic impedance cube and property cube were used to constrain the reservoir static model. These fields have highly stratified clastic reservoirs. The fields structural style consists of complexly faulted collapse crest roll over anticline.
3D porosity and permeability model were built, the seismic constrained property models using geostatistical inversion captured distinctively the heterogeneity and small scale variations in the interwell region.
Pioneer challenge Reduction of MEG consumption using KHI for hydrate control in a deepwater environment offshore Egypt
Authors: Gizah Fawaz Abd El-latif , Ali Taher Abdel Raheem , Baydoon Mohammad , Allenson Stephan , Scott Allan 
Published: July 2010

Abstract
Hydrate control in a subsea gas environment is a challenge. The West Delta Deep Marine (WDDM) sub-sea gas production and gathering system was designed to use monoethylene glycol (MEG) and methanol injection as the means of controlling hydrate formation in the Sub-sea infrastructure.
The produced fluids are transported to shore based processing facilities via two trunk lines, one 36?? and one 24??. The aqueous phase of these fluids, being a mixture of produced water, condensed water, condensate and MEG are separated and processed through a vacuum distillation system to recover the MEG.
Due to the high cost for the MEG and the unavailability of the MEG in the country, it was recommended to do something different to reduce the operating cost and maximize the production by reducing the shut down of the wells due to hydrate formation.
The first step to reduce or eliminate these problems was to reduce the MEG consumption. This was achieved by using the MEG as a carrier to apply kinetic hydrate inhibitor (KHI) at the well flow lines. This philosophy was applied first in the Sapphire field (offshore Egypt), which has the highest hydrate tendency.
The outcome was a 70% reduction in MEG consumption in this field. This paper will explain the preparation, execution of the application of KHI in the Sapphire system and cost benefits.

Introduction
The formation of natural gas hydrates in gas pipelines and oil production and processing facilities is a major operational challenge for petroleum producers. These hydrates are crystalline, ice-like compounds composed of water and natural gas that form when small hydrocarbon molecules such as methane and ethane are trapped in hydrogen-bonded water cages under conditions of high pressure (typically above 50 bars) and low temperature (typically below 30ºC). The small, individual crystalline cages tend to agglomerate, forming larger hydrate structures that can adhere to surfaces such as internal pipe walls. If allowed to form and grow unchecked, these hydrate crystals can damage the pipeline or lead to blockage of the pipeline to the point of a pipe rupture (17).
Floating Unit Hull and Mooring IMMR Plan
Authors: Franco Mireille 
Published: July 2010

Abstract
The integrity of the Floating Production Unit and its Mooring is a key point to ensure the minimum risk of pollution and production disruption due to Hull structure, Mooring, Hull system or Hull equipment.
The Floating Unit Integrity Management System aims avoiding any disturbance, shutdown, repair or even unscheduled return to dry dock.
This target can only be reached by the application of procedures and good practices, fit for purpose, leading to the proper implementation of optimised inspection and surveys programmes, in compliance with Company and statutory requirements and not only based in Class requirements.
The new built unit Hull and Mooring Inspection, Monitoring, Maintenance and Repair Plan shall be developed in an early phase, during the design and project phases in order to ensure, first, that everything is design for later on easy inspection and, second, that all items will be subjected to regular survey or maintenance: no orphan or unsurveyed items have to be allowed.
The interferences between different systems and numerous teams (SIMOPS) are also a subject to be addressed.
The unit Hull and Mooring Inspection, Monitoring, Maintenance and Repair plan is a cross-functionality job that shall be part of the hand over for an efficient and early implementation for operational life.
Multidisciplinary teams have to be involved in IMMR Plan execution and have to be experienced enough to phase the different scenarios.
One of the cornerstones is Class: all the floating units and its mooring have to be classed and maintained classed during its service life by a member of IACS. This independent assessment (Third Party) provides the basic and minimum framework focusing on personnel and structure safety.
Reference documents, procedures, good practices fit for purpose and even computerized tools have been developed in the frame of the Floating Units Integrity Management System policy.
SS: Special Session Title: High Pressure Gas-Liquid Separation. Droplet size measuring technique and application
Authors: Marchetti Jorge Mario , Patruno Luciano Emanuel , Gaebler Ansor , Winterthur A.G. , Svendsen Hallvard 
Published: July 2010

Abstract
The knowledge of droplet size distributions in a scrubber is of high importance as the removal efficiency of various types of separation equipment to a large extent depends on this. In this work, the use of a laser scattering technique to measure droplet size distributions in a medium pressure system was studied. One of the main problems encountered when using diffraction techniques, or any technique where unhindered optical access is needed, is the formation of droplets on the glasses used. Droplet formation during an experiment destroys the method accuracy. In this work, several technical modifications were done to the column in order to obtain satisfactory results via the diffraction technique.
It was establish that the modified technique is suitable for liquid droplet measurements under regular atmospheric conditions and the reduced interference made it possible to determine the accuracy of the system as well as the repetitivity of the measurements. Good reproducibility and repetitivity was obtained. Another set of tests was performed in a pilot column, where several measurement configurations were tested and in each tested configuration results relating droplet interaction with the optical access glasses were determined. These results were used to assess the effiency of the configuration and, indirectly, to estimate the efficiency of the separation equipment. Used in a scrubber, this will permit us to find how well each part of the scrubber is working, thereby possibly allowing for separation improvements.
SS: Thunder Horse and Atlantis Deepwater Frontier Developments in the Gulf of Mexico: Thunder Horse and Atlantis: The Development of Twin Giants in the Gulf of Mexico
Authors: Todd Simon , Replogle Dan 
Published: July 2010

Abstract
Since their discovery in the late 1990s, Thunder Horse and Atlantis have shared many aspects of the journey from development concept to production operations. These include significant project challenges in subsea and topsides, substantial preparation for production operations, and resounding success during production ramp-up and early operations. This paper will outline some of the similarities and key differences between the two, and emphasize the shared ingredients for success despite the frontier environment of the fields. Thunder Horse and Atlantis are both giant oil and gas fields and together produce more than 400 mboed, about 10% of BP's global production and about 6% of the U.S.'s oil production, producing through semi-submersible facilities that are respectively the biggest and the deepest moored in the world. Despite the frontier nature of the developments, and several major challenges encountered and shared by the two projects, both have been delivered and are performing at world class levels of efficiency, with long sustained futures ahead of them. The experience of the journey of these twin giants from discovery to world class operating assets holds several key lessons for megaprojects of the future, particularly in the challenging conditions of deep water.

Introduction
Every prolific hydrocarbon province in the world has at its core one or more giant oil/gas fields that form a substantial component of its discovered and developed resources, and which represent many of the challenges faced by that province as a whole. Meeting those technical and commercial challenges for the giant fields often opens the door to further development of the province and fairways. So it is in the deepwater Gulf of Mexico (DW GoM). Arguably, the Mars discovery was the giant find of Round 1 exploration in the DW GoM during the late 1980s. A decade later, Thunder Horse and Atlantis were two of the largest Round 2 exploration discoveries, and together presented some new challenges in deeper water and more complex subsurface conditions than anything previously encountered (Figure 1).
At the time of discovery both fields were characterized by promising reservoirs that were " wrapped?? in environmental conditions for which no technical solution yet existed. For Thunder Horse this centered on the pressure, temperature and corrosivity of the reservoir fluids, while Atlantis faced the subsurface image of the reservoir and the extreme water depth. This article will outline how those challenges were met, and how, more than that, both developments have commenced their operations with world class efficiency and performance.
SS: Thunder Horse and Atlantis Deepwater Frontier Developments in the Gulf of Mexico: Atlantis - A case Study in Thoroughly Planned and Scheduled Well Delivery
Authors: Sprague Jonathan David , Mix Kurt Edward , Faulkerson Joseph 
Published: July 2010

Abstract
This paper will describe the scope of the Drilling, Completion, and Subsea construction activities and the approach taken by the BP Atlantis Wells Delivery Team in planning and execution. The BP Atlantis Wells Delivery Team recognized early that in order to efficiently execute all of the drilling, completion, subsea construction, and tie back operations to the producing facility, a very disciplined Project Planning and Scheduling approach would be required. A group of dedicated, competent scheduling professionals were assigned to the Drilling and Completion (D&C) Team and proved instrumental to the successful outcome. The D&C scheduling professionals complemented the other professional schedulers strategically selected for each of the project's necessary functional teams and key construction sites. The D&C Team started gaining competency in true project management through development and recruitment as early as three years (2001) prior to the start of development operations.

Atlantis Field Development Overview
The Atlantis field was discovered in 1998 and appraisal operations continued through the project sanction in November 2002. The Gulf of Mexico field is approximately 185 miles south of New Orleans in Green Canyon Block 743 (Figure 1). The field lies in 6,800 ft of water below the Sigsbee Escarpment and is capped by a large salt body making it difficult to image the reservoirs. The escarpment is an underwater " mountain?? which slopes from a water depth of 4,400 ft to a base of 6,800 ft. The field is a subsea development consisting of multiple drill (well) centers tied back to a central floating semi-submersible production host facility known as the Atlantis Production Quarters (PQ) located about two miles south in Green Canyon Block 787 in 7,074 ft of water. The PQ has a displacement of over 97,000 tons even though it is void of a drilling rig. Instead, the PQ is solely dedicated to gathering, processing and exporting Atlantis hydrocarbons up to the facility with a capacity of 200,000 barrels of oil and 180 million cubic feet of natural gas per day.
SS: Thunder Horse and Atlantis Deepwater Frontier Developments in the Gulf of Mexico" Paper Title - Deepwater Completions: The Devil is in the Details
Authors: Rich David Alan , Rogers Bruce , Dyson W.Q. , Olson Karen , Smart John C. , Tiffin David 
Published: July 2010

Abstract
BP's Thunder Horse and Atlantis completions are some of the most complex in the world. This complexity is both a basic requirement of the environment and a result of the desire to achieve as much functionality from a wellbore as practical. This paper will address the approach BP has taken to ensure " completions excellence?? on both the completion design and installation, but will not cover the design details of the completions themselves. Completions Excellence is a mindset of continuous improvement in organizational capability, planning, execution, and learning.

Introduction
Thunder Horse and Atlantis are two of BP's premiere deepwater (DW) fields in the Gulf of Mexico (GoM). These fields are in water depths of 5,500 ft to 7,000 ft and cover a number of OCS blocks each, so multiple drill centers and the use of state of the art dynamically positioned drilling/completion rigs is required. Well depths are in the range of 19,000 ft to 28,000 ft MD. Reliable, high-rate well completions are critical for the success of these fields. Complex reservoirs with multiple stacked pay sands result in wells that typically require multi-zone sand control completions. A typical Thunder Horse or Atlantis completion may cost tens of millions of dollars and the completion itself will account for one-half to two-thirds of total well cost. Production from such wells may be over 50 thousand barrels per day. Initial completion designs were single and stacked cased and perforated or frac packed completions, but in order to improve capital efficiency, downhole flow control was added to better manage the reservoirs and minimize future interventions (Figure 1). The complexity of even the simplest DW GoM completions mean that any engineering or installation errors can cost tens of millions of dollars to fix, and that major workovers can be even more expensive.
Despite all the complexity, most of the problems encountered in delivering these wells have involved getting the seemingly minute, simple details right. Things like O-rings, metallurgy and unforeseen sources of debris have led to some of the biggest challenges. A successful completion is the culmination of getting thousands of small details right the first time through a system of checking and re-checking during design, manufacturing and assembly in the shop; and again in the field prior to and during installation. There is no doubt that to achieve completions excellence " the devil is in the details!??
SS: Subsea Well Intervention: Spoolable Compliant Guide: A Solution for Well Intervention
Authors: Bridge Christopher 
Published: July 2010

Abstract
The Spoolable Compliant Guide (SCG) is a conduit between a subsea well and a mono-hull vessel which allows well intervention toolstrings, coiled tubing and wireline to be guided into the well. The SCG consists of coiled tubing and jointed pipe suspended from a vessel and supported in a compliant " S?? shape though the water column. The compliant S shape acts to isolate the wellhead and well intervention package from the vessel's motion, which simplifies the mono-hull vessel to SCG connection, as well as the operations onboard the vessel.
Finite element studies were conducted to determine the operating feasibility, examining the effects of vessel position from the wellhead, vessel drift off, deployment and elastic and plastic fatigue life. These studies were complemented by small-scale model tests which examined pipe-in-pipe interaction, plastic and elastic fatigue, and wear of coiled tubing. The results show that the SCG from a mono-hull vessel is a feasible and cost effective alternative to rig based top tensioned risers for coiled tubing operations.

Overview of Spoolable Compliant Guide
The SCG is a conduit between the Well Intervention Package (WIP) and a vessel which allows toolstrings, conveyed by coiled tubing and/or wireline to be " guided?? into the well. The SCG consists of a length of tubular hung off at the top to the vessel and connected at the bottom to the WIP, as shown in Figure 1. The WIP contains well control equipment to control the well barriers and a lubricator that allows toolstrings to be lubricated into and out of the well. A subsea dynamic seal located at the top of the WIP isolates the guide pipe from the well fluids and pressure.
SS: Subsea Well Intervention: Experiences From Operating New Generation Riserlesss Light Well Intervention Units in the North Sea: Challenges and Future Opportunities
Authors: Friedberg Robert , Joessang Siri , Gramstad Bernt , Dalane Snorre 
Published: July 2010

Abstract
Island Offshore has since 2005 been operating riserless well intervention units in the North Sea. The first unit has successfully performed more than 50 well interventions since start April 2005. Another two units have been put into operation in 2009. Both are purpose built based on experiences gathered from the first unit.
The paper will discuss the operating experiences from the first years and how these experiences have influenced two second generation well intervention units..
Further, the presentation will also discuss challenges for this type of service as well as future opportunities

Introduction
Currently there are more than 5000 subsea wells world wide and the number is growing, particular in areas like West Africa and Brazil. In the North Sea there are approx. 1300 subsea wells of which about 500 are located on the Norwegian Continental shelf (NCS). The intervention frequency on subsea completed wells should in theory not deviate substantially from platform wells. Platform wells on average experience an intervention every 4th year, while subsea wells more rarely are being maintained.
There is a significant discrepancy between UOR (ultimate oil recovery) for platform wells vs. subsea completed wells; as from subsea wells UOR &lt; 35%, platforms wells experience &gt;50% UOR (some fields &gt; than 70%, North Sea - Statfjord).
On the Norwegian sector of the North Sea, Statoil during 2009 did totally 25 well interventions utilizing two specialized units for RLWI. The cost benefit by these operations, according to the operator, did result in a net profit of approx. $ 2,5 billion.
During 2010, approx. 40 well interventions are scheduled utilizing the same units, while a third unit will be operating on the UKCS, West of Shetlands, (WoS) extending the operation to even harsher environment.

The Units
During 2009, two of the units, (Island Frontier and Island Wellserver), have been operating on the NCS, while the third unit Island Constructor, has been operating mainly on the UKCS, WoS.