bluuebunny/crossref_metadata_2025_split huggingface dataset:
SS - Optimizing Horizontal Well Performance In Non-Uniform Pressure Environments Using Passive Inflow Control Devices
Authors: Krinis Dimitris , Hembling Drew E. , Al-Dawood Naseem Jaber , Al-Qatari Sadiq Ali , Simonian Sam , Salerno Giovanni 
Published: July 2009

Abstract
Passive Inflow Control Devices (ICDs) are used to enhance performance of horizontal wells in unfavorable environments, such as nonuniform permeability and/or pressure along horizontal sections. This is the first attempt at using ICDs to manage inflow along horizontal wells with substantial reservoir pressure differential.
This paper presents how passive ICD completion technology is used to optimize well productivity and reduce water production in a well with significant reservoir pressure differential across the horizontal section. Prior to running the ICDs, this horizontal carbonate well exhibited a nonuniform production profile, cross-flow, and high water production resulting in reduced well performance.
A production log of the initial (open hole) completion confirmed downward cross-flow of fluids from heel to toe and production contribution from only the first 10% of the horizontal section. Following the installation of the ICD system, water production was greatly reduced and oil rate doubled indicating significant improvement of the well performance. A second PLT survey showed contribution from the entire horizontal section and elimination of the cross-flow.
The key factor in the success of this project was the ICD system design derived from numerous wellbore hydraulic simulations, determining the appropriate number of ICD units and compartments.

Introduction
Horizontal wells have been globally used to maximize reservoir contact and ultimately improve well performance. Variations in permeability, pressure and frictional pressure drop along horizontal sections can create nonuniform inflow profiles, which can lead to early breakthrough of water or gas in reservoirs with an aquifer and/or gas cap. Breakthrough typically occurs in regions of high permeability or at the heel of the lateral section in homogenous reservoirs. This ultimately leads to a reduction in reserve recovery and well performance.
The use of ICD systems to effectively manage nonuniform inflow profile has been described in past publications1-4. In this paper, ICDs were used to control nonuniform pressure profile. The variation in reservoir pressure was 200 psi from heel to toe, with high pressure at the heel.

Background
Horizontal wells are common practice in this giant Middle East field with a production history of more than 50 years. The reservoir is a composite Jurassic carbonate anticline, with several gently dipping crestal regions containing undersaturated Arabian Light grade oil. Full pressure maintenance was initiated in the 1980s by peripheral power water injection. Infill drilling is still underway tapping oil behind the flood front areas utilizing horizontal well technology. The most prolific zones in this gravity dominated reservoir exhibit high matrix (300 mD - 2,000 mD) permeability, which is the principal source of production.
Motion Behaviour of the Mono-Column FPSO Sevan Piranema in Brazilian Waters
Authors: Saad Arthur Curty , Joao Leonardo Vilain , Loureiro Rodrigo Reis , de Brandao Renilton , Filho Remo Zauli Machado , Lopes Clovis , Gioppo Heitor Luiz 
Published: July 2009

Abstract
The world's first floating, production, storage and offloading (FPSO) mono-column type platform was installed in June 2007 in the Piranema field, located offshore Sergipe state, Brazil, in 1,090 meters water depth. The unit is equipped with a process plant capable of handling 30,000 bpd (41 to 44º API) of crude, and capacities for 2,400,000 Nm3/day gas compression and 300,000 barrels oil storage. It was designed, built and commissioned by Sevan Marine according to the novel concept. The unit is currently being operated by Sevan Marine for Petrobras under a long-term charter contract.
A Technical Cooperation Agreement, between Petrobras and Sevan Marine to investigate the mono-hull concept since initial tank tests, also allowed monitoring motions and environmental data since the platform was commissioned, under a project led by Petrobras Research and Development Center.
This paper is intended to provide information on the motion behavior of a mono-hull production platform in real environmental conditions, and presents a comparison among data acquired from field measurements and results from numerical simulations as well as from model tests performed during the design phase. Other FPSO key functionalities are also addressed in this paper, such as the offloading operations and mooring system performance.

Introduction
The current drive to produce offshore oil fields in deep and ultra deep waters has pushed oil companies and operators to pursuit novel concepts for production units which are capable of storing and offloading the oil to shuttle tankers. The mono-column floating production platform is considered a unique concept of great interest by the industry. The expected enhanced motion behavior of this concept in comparison to ship-shaped production units is very beneficial for the performance of the production plant, safety of the crew and mainly for long-term integrity of the risers connected to the platform. Moreover, the mono-hull concept has good constructability with low capital expenditure during construction. Easiness of installation is also considered one of the advantages of this mono-column concept.
BP King - Deep Multiphase Boosting made Possible
Authors: Davis Brian Edward , Kelly Cathal , Kierulf Katrine , Eriksson Klas Goran , Normann Truls , Homstvedt Gunder 
Published: July 2009

Abstract
The BP King subsea pumps were commissioned in November 2007 in record-breaking water depth of 5430 ft (1700 m) offshore Louisiana in Gulf of Mexico (GoM). Two twin-screw multiphase pumps were installed with a 17-mile (27 km) tieback to the Marlin Tension Leg Platform (TLP). Besides the technical challenges that have been overcome in this record breaking project, installation and commissioning under these conditions are a major achievement.
This paper gives a presentation of the system evaluation ahead of launching the project and the various engineering tasks during design of the system. The complete pump system with all necessary topside and subsea components is presented and discussed. Attention is also given to training, pre-deployment work, installation and commissioning of the pumps. This joint BP America Inc. (BP) and Aker Solutions ASA paper also describes the operational experience and methods for continuous monitoring of the various sub-systems at the pump station.

Introduction
BP King is an oil field located in the Gulf of Mexico (GoM). It consists of three wells, King D5 and D6, producing since 2001 and King West, D3, producing since 2003. The wells are located in water depths ranging from 5000 to 5430 ft (1520 - 1655m). All three wells are 100% owned by BP and are produced back to the Marlin TLP which is also operated by BP. The field is located approx. 100 miles (160 km) offshore the coast of Louisiana in the GoM.
The Marlin Tension Leg Platform is located approximately 86 miles SSE of Venice, Louisiana in Viosca Knoll Block 915 at a water depth of 3245 feet. There are a number of fields that are tied back to the TLP and one of the longest of those is the King Field Complex. The wells are connected via rigid jumpers to one of the two flowlines going back to the Marlin TLP approximately 17 miles (27 km) away.
As pressure in the reservoir has been declining, BP initiated studies of various methods of keeping up the production and increasing the field life. A structured approach was applied throughout the project period based on BP's project execution stage gate process:Appraise - Determine the feasibility of the project and align with business strategySelect - Select the preferred project option and establish execution plan and fundingDefine - Finalize project scope, cost, schedule and execution plan. Complete contract negotiations with key suppliersExecute - Procure and install equipment in alignment with scope, cost and schedule targets.
H2S Scavengers Injection: A Novel Evaluation Protocol To Enhance The Integrity Of Production Lines
Authors: Mendez Conchita , Magalhaes Alvaro A. Oliveira , Altoe Pedro , Acosta Eduardo 
Published: July 2009

Abstract
The phenomenon of reservoir souring occurs when the concentration of hydrogen sulfide (H2S) increases in the produced fluids. The origin of H2S has generally been linked with secondary recovery operations. One common secondary recovery operation involves the injection of water, often seawater. Many oil operators have associated seawater breakthrough with subsequent souring. H2S can also have geological origin (e.g. thermal decomposition of organic sulfur compounds which are present in some crude oils).
The corrosiveness of co-produced water from the oil reservoir will consequently change with reservoir souring. Though carbon dioxide can cause very severe corrosion (i.e., general and pitting) of steels, H2S corrosion is more localized, and can cause cracking. Hence, increasing H2S will not necessarily cause a linear increase in general corrosion rate, but rather induce sudden failures in susceptible materials.
One alternative to mitigate the effects of H2S in oil and gas production facilities is the injection of H2S scavenger chemicals at suitable points in the system. Liquid scavengers react with H2S to form stable water- or oil-soluble reaction products.
The effects and performance of H2S Scavengers at various operational parameters (i.e., type of crude, water cut, temperature, contact time, and flow pattern) are not completely understood. A laboratory testing protocol and experimental equipment was designed and constructed in order to:evaluate the performance of H2S scavengers under simulated multiphase flow field conditions, andfacilitate the selection of commercial products to be injected into oil lines through a gas-lift system and/or through umbilical lines.
This work presents field and laboratory data as well as a description of the basis of computational modeling developed for the control of H2S in off-shore production fluids through the injection of liquid H2S scavengers through gas lift or umbilical line. The ultimate goal of this chemical treatment is to control the corrosion of carbon steel risers for a reliable operation during the lifetime of the producing wells by controlling the levels of H2S.
The major achievement of this work is the development of a testing and simulation approach to select the best chemical treatment and optimal doses minimizing the cost and uncertainties associated to field trials particularly when production conditions change.
SS:Geohazard Risk Assessment-Pipeline integrity in geohazard prone seabed terrain - what is the real risk?
Authors: Nicholls James 
Published: July 2009

Abstract
Geohazard features can now be mapped in great detail to all required water depth as a routine and mature task for the design and installation of submarine pipelines. The perceived risk associated with some of these highly characteristic morphological and geotechnical phenomena remains however a combination of quantitative modelling and engineering judgement.
This note references examples of several deepwater long distance pipeline projects in which geohazard has played a dominant factor in the assessment of risk to the pipeline, and revisits the application of engineering geohazard assessment to pipeline routeing and design. Geohazard in this context is limited to geological process at or near seabed that could result in catastrophic damage and loss of containment.

Introduction
Project's requiring the design of a pipeline system that traverse's coast margin shelf, slope and deepwater basin, will encounter a range of ‘normally’ expected and generally well understood geological terrain, each of which will include characteristic process and features at the seabed presenting potential risk to pipeline integrity. Pipeline engineering in deepwater therefore requires an early and authoritative appreciation of the regional setting for route selection, in support of key decisions regarding project concept, feasibility and investment
The observations and opinions discussed below are from the author's experiences both in the engineering supervision of geohazard specialists and as Project Management Team advisor on engineering geoscience and survey aspects for deepwater pipeline design.

Base Data
The overall bathymorphological configuration of coastal shelf, slope and abyssal plain for long distance pipelines is initially established from public domain bathymetry, generally satellite derived data (approaching 1 km resolution) and maritime navigation charts. Mature area development projects locally benefit from high quality exploration derived bathymetry data as a starting point (normally better than 100m resolution). In certain areas of high academic and industry funded research interest, we may be fortunate to access reconnaissance survey grade bathymetry data (typically 30 m resolution) including geophysical data and geological cores with regional interpretation.
During the subsequent Engineering Design phases, the resolution and fidelity of the seabed imagery and quantitative description improves to a point at which confidence in the final assessment of risk to the physical and economic security of the pipeline can be validated. However, it remains the careful and considered planning of initial route geometry and provision for alternatives at the project feasibility level which governs overall efficiency of engineering effort and the most appropriate final design alignment.
SS - Sakhalin-1: Regulatory and Environmental Management
Authors: Tyler David C. , Egging D.E. , Fedak M.E. , O&apos;Reilly J.E. , Gauptman E. , Reep B.E. , Romanova M. , Scott M.J. 
Published: July 2009

Abstract
This paper reviews the environmental and regulatory performance of ExxonMobil Development Company (EMDC) and its contractors during Phase-1 development of the Sakhalin-1 Project Chayvo Field offshore Sakhalin Island, Russia, from 2002 through 2007. The Sakhalin-1 Project is being developed under a Production Sharing Agreement (PSA) with ExxonMobil's local affiliate, Exxon Neftegas Limited (ENL), serving as the operator for an international consortium of Russian, Japanese and Indian partners. 1
The Phase-1 development of Chayvo field is the first year-round offshore project to be completed in Russia. First oil was in October 2005 and the project reached full production by February 2007. To ensure good relationships and support from local, regional and federal government authorities, ENL implemented its global best practices for environmental performance and regulatory compliance. As measures of its success, ENL was awarded Foreign Project of the Year by the Russian publication, RusEnergy in 2006 and received the Excellence in Project Integration Award at the 2008 International Petroleum Technology Conference.
This paper demonstrates the need for early, comprehensive planning for environmental performance and regulatory compliance, including project approvals and permitting. It describes Russia's dynamic and complex regulatory framework and underscores the value of local expertise and professional relationships with Russian authorities. This paper also offers lessons learned from ENL's efforts to monitor Western gray whales and Steller's sea eagles, its oil spill prevention planning, archaeology, public consultation and other programs. The information and related lessons learned may be useful for future oil and gas developments, and could help benchmark similar projects or identify issues that other operators might face.

Introduction
The Sakhalin-1 oil and gas development, located on the northeast shelf of Sakhalin Island, includes the Chayvo, Odoptu and Arkutun-Dagi fields. Together they contain an estimated 2.3 billion barrels (307 million tons) of oil and 17.1 trillion cubic feet (485 billion cubic meters) of natural gas. Although hydrocarbons were discovered offshore Sakhalin in the 1970s, the technology to produce them was not available. The current phase of exploration and development began when the production sharing agreement became effective in 1996.
Exxon Neftegas Limited (30 percent) operates the Sakhalin-1 Project. The consortium includes two Russian companies, Sakhalinmorneftegas-Shelf (11.5 percent) and RN-Astra (8.5 percent), the Japanese company, SakhalinOil and Gas Development Co., Ltd. (30 percent) and India's ONGC Videsh Ltd. (20 percent). Both Russian partners are affiliates of Rosneft, the Russian state-owned oil company.
SS: Cryogenic Pipeline-Risk Analysis of LNG Pipe in Pipe Options
Authors: Spitzenberger Cynthia M. 
Published: July 2009

Abstract
A liquefied natural gas (LNG) liquefaction terminal used a comparative risk assessment to evaluate four different pipe-inpipe options for the loading line design to an offshore jetty system. The safety risk posed by the installation was evaluated with a quantitative risk assessment (QRA) procedure. A separate qualitative assessment was performed to evaluate the security risks associated with the project. Evaluation of the pipe-in-pipe and pipe-in-pipe-in-pipe technologies required additional frequency analysis to address the extra protection layers provided by the multi-pipe designs. The risk assessment process for the novel designs provided a more detailed basis for selection between the alternatives.

Introduction
Quantitative risk assessment (QRA) is a systematic analysis of the risks posed from hazardous activities or situations. The quantified or calculated results can be used in support of decision making. A liquefied natural gas (LNG) liquefaction terminal used a comparative risk assessment to evaluate four different pipe-in-pipe options for the loading line design to an offshore jetty system. The safety risk posed by the installation was evaluated with the traditional quantitative risk assessment procedure. A qualitative assessment was performed to evaluate the security and economic risks associated with the project.

Methodology
The approach used in the study was that of a classical risk assessment (CCPS 1999); a systematic approach to the analysis of what can go wrong in complex industrial systems. The normal conditions of operation of the system are defined and then the following questions asked:What accidental events can occur in the system?How frequently would each event occur?What are the consequences of each event?What are the total risks (frequencies multiplied by consequences) of the system?What is the significance of the calculated risk levels?
These questions correspond to the basic components of risk assessment discussed in Figure 1. Once a system has been analyzed, if the risks are assessed to be too high according to the desired criterion, the system would be modified in order to reduce the risks to a tolerable level, and the risk levels then recalculated. The process may therefore be viewed as iterative, where the design and/or operation of the system may be changed until it complies with the needs of society.
Managing Geohazards on Offshore Oil and Gas Projects
Authors: Carmichael Robert , Blackmore Malcolm Stuart , Nunan Frank 
Published: July 2009

Abstract
When one considers the areas throughout the world where seabed geohazards exist, their significant to the offshore oil and gas industry becomes apparent. The potential impact of geohazards on offshore development projects can range from increased intervention works which impact project schedule and costs, to scenarios where the overall integrity of the facility over its design life is at risk. The technical and commercial challenges posed by geohazards are more acute on projects with marginal economics, on fast track schedule projects, and where turnkey installation contracts are used. The earlier in a project cycle that geohazards are assessed, the more can be done to mitigate their effect on the project and this can be achieved at appraisal or concept selection phases by performing a desktop study which can use exploration seismic data as an invaluable source of information regarding the development area. It is recommended that geohazard specialist be engaged during such a desktop study and retained through the various design stages of the design to ensure continuity in the work. This can prove difficult to manage contractually, however it is still considered to be the optimal technical solution. Risk assessment based approaches are generally used to manage the risks associated with geohazards. The geohazard risk assessment process is iterative and requires the detailed geophysical and geotechnical survey data, hence the implications of any serious consequences arising from the geohazard risk assessment may only be know at an advanced stage of a project.

Introduction
In areas prone to seabed geohazards, these can pose serious risks to offshore oil and gas production facilities, personnel and the environment. This paper provides an overview of seabed geohazards and their potential impact on offshore oil and gas projects. It also critiques how geohazards are typically managed during the implementation of such projects through the various stages from concept selection through design, and construction. Specific areas addressed are planning, data gathering, mangagment of engineering and the effects of geohazards on project schedules. Recommendations to improve the management of geohazards are also discussed.