bluuebunny/crossref_metadata_2025_split huggingface dataset:
Community Based HSE Projects—Eni NAOC Contribution to Niger Delta Development
Authors: Tavolini E. , Onyia J. , D'Ippolito D. 
Published: December 2007

Abstract

Description of the Paper
Community based HSE project is a new strategic approach in Eni-NAOC (Ente Nationale Idrocarburi - Nigerian Agip Oil Company) activities to address host community issues and achieve beneficial goals in the Niger Delta.
Eni-NAOC main community based projects are numerous.
The following have been chosen for this paper:
Kalabile-Ama mangrove rehabilitation Gas Master Plan Okpai Power Plant Green River Cottage Hospital Ologoama
These projects are multi sector related and provide integrated benefits to stakeholders participating to the initiatives.

Application
To demonstrate that, through carefully planned community based projects, NAOC has improved the HSE aspects connected to the operational activities and the relationship with the stakeholders.

Results
The paper provides an in depth description and analysis of the major community projects developed and the related outcomes:
Environmental risk mitigation and protection Technology transfer and host community economic empowerment Improvement in living conditions, public health & hygiene

Environmental risk mitigation and protection
conservation of natural resources through reforestation, land development practices, utilization of gas and reduction of wasteful flaring and GHG (Greenhouse Gas) emissions.

Technology transfer and host community economic empowerment
skills acquisition and transfer of basic technology at the grassroots through direct training and apprenticship and agric extension services, provision of gainful employment opportunities, with the beneficial rewards of sustainable development, reduction in rural-urban migration, reduction in host community hostility towards company, reduction in conflicts and activity disruption.

Improvement in living conditions, public health & hygiene
access to clean water and air, improvement in food availability and quality; access to health care, improvement in living conditions, availability of basic housing.

Observations
Awareness campaigns and human resource development are the necessary ingredients for the successful implementation of HSE Community based Projects in Niger Delta operational environment.

Conclusions
Strategic HSE projects that are community based are positively impacting on the business environment and are increasingly being solicited and supported by host stakeholders, Governments and Civil Institutions.
Eni-NAOC has improved the HSE aspects relating to operational activities; such improvement has led to a better operational environment and better living conditions in the host communities and of the peoples, and a consequential beneficial improvement in the relationship with stakeholders.
Analysis of Alternative Well-Control Methods for Dual-Density Deepwater Drilling
Authors: Stanislawek M. , Smith J. R. 
Published: December 2007

Abstract
Development of deepwater resources is often limited by the high capital costs involved. Dual gradient drilling methods have been proposed to provide simpler, safer, more economic well designs and therefore increase the ultimate development and utilization of deepwater gas resources. Riser gas-lift was investigated as potential means to implement a dual gradient system. A primary concern was whether effective well control was possible in a system containing so many different density fluids and different flow paths. That concern was studied using a transient, multiphase simulator. Well control was found to be feasible when using methods generally analogous to those for conventional operations.
Deep Gas-Well Cementation: A Review of Risks and Design Basis for Use of a Liquid Cement Premix for Large Offshore Cementing Operations
Authors: Benge G. , Darby J. , Peroyea M. , Aguilar T. , Mueller D. , Doherty D. 
Published: December 2007

Abstract
Large volume offshore cement jobs can present a number of challenges. Larger casing strings set to deeper depths have driven up the volume of cement jobs beyond the capacity of many rigs. A recent well design called for two cement jobs that would exceed 2,400 bbl. There were a number of options considered for dealing with these large cement jobs. These included spotting lift boats beside the rig, the use of a dedicated cementing vessel, the deployment of ocean going barges, spotting an additional jack up rig, or the use of a liquid cement premix.
This paper discusses the risk analysis and development plan that led to the selection of a liquid cement premix for the large volume jobs. The paper covers the design requirements of the jobs and addresses the risks associated with the available options. Information is provided on risks associated with boat and barge stability, draft limits at available bulk facilities, deck load limits and logistics of alternative designs. Rig based pumping operations are included with respect to logistics and timing issues related to placing the entire operation on the rig.
These jobs were to be the largest liquid cement premix jobs to date. Slurry stability and consistency were major concerns on these jobs. These were addressed through full scale testing on the vessel. (The results of which are summarized in SPE 988941.) The paper further covers the equipment requirements and mixing needs and compares the selected option to that of a conventional cement job.
First Hyperstatic Riser Joint Field Tested for Deep Offshore Drilling
Authors: Poirette Y. , Guesnon J. , Dupuis D. 
Published: December 2007

Abstract
The long riser is the key element for deep offshore drilling. The total weight of the system increases rapidly with the water depth in the same way as the required tensioning capacity. Static loads and fatigue become critical and threaten the riser integrity. Furthermore, the natural period of the riser in the disconnected mode reaches the wave energy window and seems able to put the riser in a dangerous resonant state.
A new technology developed by IFP for integrating riser joints is presented in the paper which allows to reduce by up to 30% the weight of the system and to significantly lower the natural period. It consists in joining together all the pipes constituting the riser (main pipe and peripheral lines) in so manner to share the axial tension between all of them. This hyperstatic working mode may be used conjointly with hybrid (steel/composite) kill & choke lines previously developed.
After a first step of riser analysis and technical studies through extensive FEA and CAD, a field test was decided to bring information on the capacity of the technology to work properly in the operational context of a drilling rig and to maintain in the time the hyperstatic working mode of the riser joint. The Pride Angola drillship was chosen for the test. A preliminary phase consisted in designing all the mechanical changes to achieve in the riser joint: adding two hybrid auxiliary lines, fixing the lines at both ends, integrating partial instrumentation (6 sensors). Then, a qualification phase consisted in carrying out all laboratory tests of the relevant equipment. A special testing fixture was built at IFP for that purpose. The operating phase started July 2005 for a minimum of 6 months and data was recorded during drilling operations to check the working conditions of the riser joint.
The paper presents the basis of the technology, describes the three phases of the field test and comments the first results obtained from the rig. To conclude, the technology is then put in the context of deep sea drilling and its benefits are discussed for conventional, slender and dual gradient risers.
A New Extreme HP/HT Viscometer for New Drilling Fluid Challenges
Authors: Gusler W. , Pless M. , Maxey J. , Grover P. , Perez J. , Moon J. , Boaz T. 
Published: December 2007

Abstract
Growing demand for natural gas in North America is driving the E&P industry to look for new resources in previously unexplored areas and the deep Gulf of Mexico (GOM) Continental Shelf is currently attracting a lot of attention. Several of the current deep shelf HP/HT wells have anticipated bottom-hole temperatures that significantly exceed the limits of existing MWD/LWD tools; therefore, down-hole annular pressure measurements will not be available for pressure management. This leaves temperature/hydraulic models as our best, if not our only source of down-hole pressure information. These models depend on accurate surface inputs and laboratory measured fluid properties under down-hole conditions. Unfortunately, these anticipated temperatures and pressures also exceed the operating limits of conventional HP/HT viscometers. This lack of measured fluid properties under these extreme conditions will severely limit the ability of hydraulic models to predict down-hole pressures. A new extreme HP/HT (XHP/HT) concentric cylinder viscometer was designed and built to fill this important technology gap for the GOM deep shelf HP/HT wells. The instrument is capable of measuring typical drilling fluid viscosities up to 600°F (316°C) and 40,000 psig (276.0 MPa) and is capable of accurate measurements of drilling fluid properties containing ferromagnetic materials. Subsequent verification and validation testing proved the new viscometer compares favorably to commercially available field viscometers and more sophisticated laboratory rheometers and therefore lends itself towards widespread industry use. This paper reviews the development of the instrument, automated control system and HS&E issues related to testing drilling fluids at these extreme conditions. The paper will also present results of the verification and validation testing on invert-emulsion drilling fluids.
Investigation of Smaller-Footprint Drilling System; Ultrahigh-Rotary-Speed Diamond Drilling Has Potential for Reduced Energy Requirements
Authors: Judzis A. , Boucher M. , McCammon J. , Black A. D. 
Published: December 2007

Abstract
This paper describes proof of concept testing of an ultra-high rotary speed drilling system and its applicability to hard rock drilling performance. The drilling system includes the use of thin-walled diamond bits driven at extremely high rotational speeds. This program is partly funded by the DOE. Results from this study demonstrate the feasibility, verification, and characterization of the system combining high speed and sharp, low depth of cut diamond bits. This is leading edge technology.
The review of industry practices has shown that in general, rotational speeds above 1000 RPM have not been utilized in the drilling of oil and gas wells. Rotational speeds from 1000 to 50,000 RPM are used to machine or remove hard materials in other applications. These materials are removed efficiently using high RPM and small thrust loads. The drilling and coring industry does not currently practice this technology. The paper presents data and resulting drilling performance of a number of specially designed thin wall diamond core heads in a variety of rock formations tested at bench scale.
The results show rates of penetration in different rock types while calculating expended energy. Most promising are specific energies that decrease at higher face velocities, possibly showing that rock failure mechanisms change. The significance of a smaller footprint drilling system is the ability to drill into rock with low weights on bit and at low energy levels while maintaining high rates of penetration. For many operators, high well construction costs occur in hard rock areas. An improvement in penetration rates while minimizing expended energy is an opportunity to reduce drilling costs and drastically improve project economics. The estimated annual cost to drill hard rock in North America is in excess of $1.2 billion.
Testing of full-face bits is the next step. Future applications may include slim hole drilling with downhole electrical, PDM, or turbine drives though some operators view better performance is also possible in conventional hole sizes such as 8-1/2 inch. Adaptation to the oilfield will require innovative bit designs for full hole drilling or continuous coring and the eventual development of these downhole ultra-high speed drives.
Analysis of Gas Kicks in Multilateral Wells Utilizing Computer Simulation
Authors: Schubert J. , Choe J. , Dreher D. , Juvkam-Wold H. 
Published: December 2007

Abstract
Multilateral well control is an issue in today's petroleum industry that has not had sufficient study to date. Many operators are drilling multilateral wells, with limited knowledge of the pressure characteristics in the multiple wellbores as well as how the pressures in the individual laterals are related. If a kick occurs in a multilateral well, the operator must be able to determine which lateral or laterals the kick is in, as well as the effect that circulation of the kick can have on the pressures in the other laterals.
This paper reports the results obtained in a study that has been conducted utilizing a Multilateral Well Control Simulator developed at Seoul National University and Texas A&M University.1-3 This simulator calculates and records the pressure profiles in all laterals, on a continuous, basis during tripping, drilling, and well kill operations. From these simulations, we can determine the effect that the changing annulus pressure profile can have on all of the laterals.
Depending on the relative pressure gradients of the different laterals with respect to each other, kicks can actually be induced in one lateral while circulating gas from another and as the gas enters the mother wellbore. For safe and efficient well control, the operator must have knowledge of the formation pressures in each lateral so that steps can be taken to prevent the changing annulus pressure from inducing additional kicks in the other laterals.
The industry now has a study and tool which can help operators drilling multi-lateral wells to better understand how pressure changes in one lateral effect the others. This tool will allow a better understanding of the pressure changes in multiple lateral sections that will occur during well kill operations.
Displacement of Drilling Fluids and Cased-Hole Cleaning: What Is Sufficient Cleaning?
Authors: Berg E. , Sedberg S. , Kaarigstad H. , Omland T. H. , Svanes K. 
Published: December 2007

Abstract
The need for an efficient displacement of drilling fluids from cased wells prior to installation of completion equipment has been relatively undisputed in the past.
Several different fluid systems has been applied as well as a variety of different mechanical tools to achieve what is considered to be a clean well in order to safely run advanced completion equipment in the well. In contradiction to the requirements related to running more advanced equipment in the wells is the fact that several of the fields on the Norwegian shelf are entering the mature phase and tail end production. For these fields the margins are less and a significant focus is put on cost efficient solutions. In many cases, the need for casing cleaning in conjunction with displacement of drilling fluids is questioned.
The current paper are reviewing in detail the results from drilling fluids displacement and cased hole cleaning operations performed on 192 wells on the Norwegian continental shelf over the six past years.
These wells cover a variety of different completion scenarios where both water based and oil based drilling fluids have been utilised.
The results from the survey are presented with a focus on the requirements towards a clean well and the ability to measure the efficiency of the different fluid systems and operational procedures utilised.
The paper discuss different casing cleaning requirements versus well completion scenarios and displacement techniques.
Durability of Oilwell Cement Formulations Aged in H2S-Containing Fluids
Authors: Lecolier E. , Rivereau A. , Ferrer N. , Audibert A. , Longaygue X. 
Published: December 2007

Abstract
In the next few decades, the production of oilfields with high contents of associated sour gases will increase. For instance, we estimate that 40% of the world remaining gas reserves contain more than 2% of CO2 and/or more than 100 ppm of H2S. Therefore, investigations on technologies to produce such fields are of utmost importance. Due to the presence of corrosive gas, special attention has to be paid to the design of well materials (casing, cementing materials). Corrosion of steel due to acid gas containing brines is well documented in the literature, and to a lesser extent, data about the degradation by wet CO2 or wet H2S can be found. For cementitious materials, one can find abundant literature dealing with deterioration of cement pastes due to CO2 environment. Published data on degradation mechanisms of cement-based materials exposed to H2S environments are more scarce. This paper addresses the problem of durability of oilwell cement in different hydrogen sulphide environments.
Different periods of time can be identified in the lifetime of the wells: the production period (about 20 to 40 years), the post-abandonment period (some tens of years following the permanent well abandonment) and the abandonment period (several centuries). For each period of time, cementing materials (primary cementing, plugs) are in contact with different types of fluids. Therefore, to correctly assess the behaviour of oilwell cement, ageing tests have to be carried out in fluids representative of these different periods of time. In this paper, we present the methodology implemented under HP/HT conditions for ageing tests of materials in H2S-containing fluids and results obtained on cement-based materials. Main physico-chemical degradation mechanisms of cement-based materials due to H2S are identified using different characterization techniques. Depending of the nature of the fluid in contact with cementitious materials, severe degradation can occur with dramatic impairment of macroscopic properties.
Evaluation and Application of Real-Time Image and Caliper Data as Part of a Wellbore Stability Monitoring Provision
Authors: Greenwood J. , Bowler P. , Sarmiento J. F. , Willson S. , Edwards S. 
Published: December 2007

AbstractWellbore instability remains a leading cause of drilling nonproductive time (NPT), despite a considerable amount of work on the subject in recent years. For the most part this is not caused by a lack of understanding of the mechanics of wellbore instability. Rather, it is caused by the limitations of pre-drill subsurface predictions. In other words, it is the drilling surprises often encountered in reality, but not predicted prior to drilling, that give rise to wellbore instability problems. These surprises include formation tops and pressures occurring at different depths than predicted and the presence of unexpected faults or other fractured or fissile zones.Typically, while drilling today, downhole data useful for understanding wellbore stability is scarce. Much of what we have to go on is indirect measurements; torque and drag observations, cavings, and annular pressure measurements. In order to unambiguously understand and therefore mitigate the wellbore instability problem, more information is needed.Real-time wellbore stability modeling goes some way toward this goal. However, the missing piece in almost all cases is some direct observation of the state of the hole to determine where and how the wellbore is failing. LWD calipers and/or wellbore images can provide such information, and the option of transmitting the information to surface while drilling is now often possible.This paper will present the results of a project conducted to evaluate the available real-time images, memory density images, and acoustic caliper information and their incorporation into an existing wellbore stability monitoring service.
Mitigating Application-Specific Challenges Through a Total System Approach
Authors: Stavland M. , Wolter H. , Evans J. G. 
Published: December 2007

Abstract
Economical demands within the oil and gas industry are the driving force to exact significant advances in Drilling and Formation Evaluation Technology. This has been exemplified by the application of new technology to address the complex challenges of the Troll Field Reservoir in the Norwegian North Sea.
Exploiting the Troll reservoir requires horizontal geosteering through relatively unconsolidated sandstones with localized zones of hard calcite-cementation. Optimum well placement is of the utmost importance and demands reduced tolerance for any inaccuracy within the thin oil reservoir column throughout the progressively increasing drained hole section. Consequent to the advancement in drilling technology, the horizontal reach has been extended from some 500 meters to more than 5000 meters in a single reservoir section including horizontal turns of up to 360°.
In 2001 an innovative service was introduced to the Troll field, being founded on a new multi-sensor data acquisition and processing Measurement-While-Drilling (MWD) tool. The downhole tool contains various dynamics and mechanical sensors, and a high-speed data processing system to continuously provide an accurate picture of the downhole conditions and the energy transfer train. The service was deployed to optimize the mechanical efficiency of the drilling process by facilitating the immediate response to differing situations encountered while drilling complex heterogeneous formations. This real-time service, but also the intrinsic detailed studies on BHA and bit design with ensuing in-depth knowledge capture have lead to a comprehensive understanding of the Troll drilling challenges and thereby facilitated the design and utilization of application specific bottom hole assemblies with associated relevant drilling procedures and practices.
This paper will discuss how this technology is used and how this total drilling system deployment concept has been applied to successfully surmount the specific challenges of the Troll Field.
Integrating Emerging Drilling Methods From Floating Drilling Rigs—Enabling Drilling Solutions for the Future
Authors: Kozicz J. R. , Juran T. L. , de Boer L. 
Published: December 2007

Abstract
Drilling offshore oil and gas wells is more challenging than ever. Drilling problems resulting from narrow margins between collapse and fracture pressures, pore pressure uncertainty, high pressure, high temperature, and wellbore instability have resulted in significant additional cost because of the time required to rectify these drilling problems.
These problems can occur in both shallow and deepwater areas and are similar to drilling problems encountered in many land drilling areas. These problems have multiple origins related to: geo-mechanics, rock and fluid chemistry, temperature, local and regional tectonic stresses, abnormal or sub-normal pressures etc. Many methods have been developed or proposed to address these wellbore stability problems. These included: addition of wellbore strengthening agents, wellbore temperature management, expandable casing, and wellbore pressure management among others. This paper considers those methods related to wellbore pressure problems, and the tools and techniques that have been developed to overcome these.
The paper discusses the challenges and possible solutions required to cost effectively integrate these Emerging Drilling Methods with existing offshore drilling equipment to facilitate deployment of these drilling methods from floating drilling rigs.