bluuebunny/crossref_metadata_2025 huggingface dataset:
Standby Treatment vs. Malaria Chemoprophylaxis: Can We Prevent Malaria Deaths Without the Use of Continued Chemoprophylaxis?
Authors: Shallenberger L. G. , Johnson C. E.
Published: December 2007

A global Malaria Control Program (MCP) was implemented requiring non-immune workers to take malaria chemoprophy-laxis when traveling to and working in malarial areas. Despite intense health education efforts, four malaria deaths occurred in workers after they left malarial areas. A Malaria Chemo-prophylaxis Compliance Program (MCCP) was added to the MCP to verify the use of approved antimalarial medications in workers' urine. Results from MCCP tests suggest that there is a high level of medication compliance. Since the inception of the MCCP there have been questions regarding possible ad-verse side affects of taking long-term malaria chemoprophy-laxis. An alternative strategy to continued medication use would be to recommend that individuals carry stand-by treatment that could be used for early diagnosed cases. If stand-by treatment programs could achieve the same level of effective malaria control as programs that require long-term chemopro-phylaxis they could reduce the costs of prescribing medications to large numbers of workers and the potential for these individuals to experience adverse health effects from taking the medications. The authors conducted an extensive literature review and concluded that stand-by treatment alone could not be recommended for use in high risk P. falciparum areas unless the non-immune individuals were more fully trained in using all other protective strategies and supplies for prevention and treatment. We would also need to have access to reliable and updated malaria transmission data for the areas where our employees worked and lived before we could adjust chemo-prophylactic recommendations by region and season.
Removing Oil and Grease From Produced Water Using Microbubble Flotation Technique: From Theory to Field Practice
Authors: Hayatdavoudi A.
Published: December 2007

The paper addresses the issue of using micro-bubble flotation technique for cleaning the produced water such that the output (effluent) water meets or exceeds the US EPA or country-specific standards. The joint cooperation between academia and the service industry and shared field and theoretical studies have revealed the following results: (1) micro bubbles, using acetylene (C2H2) gas medium, at 55 psi backpressure on a patented Dissolved Gas Flotation pump and constant temperature, can remove 97% of the Oil and Grease from water, (2) a theoretical scaling law has been devised for estimating the potential solubility of gas in water, for example CH4 and C2H2, where Henry's Law might not be linear due to complex bubble hydrodynamics, pump pulsation, the rise of a multitude of bubble sizes in the fluid column, distribution and number of bubbles, partial pressure and concentration (molality) of the main gas and the leaked air impurities in the recycling system, and other variables, the mechanism controlling the removal efficiency of the flotation cell is related to the number and the uniformity of micro bubbles rather than their size only-the sizes range from an average of 5 to 200 microns at sampling points, (4) at sampling points, the bubble count and the gas-filled bubbles as a percent of the unit bulk volume are nonlinear periodic functions of the operating pressure of the flotation cell, and (5) there exists an optimal operating pressure of the patented Dissolved Gas Flotation pump system such that the flotation cell gives the best results and this optimal pressure can be easily adjusted by field personnel to achieve the most efficient removal of Oil and Grease from water.

Based on these results, one may conclude that a seemingly complex mix of gas chemistry and bubble thermo-hydrodynamic properties can offer a simple, efficient, and environmentally friendly technique for cleaning the produced water.
Helicopter Safety in the Oil and Gas Business
Authors: Clark E. , Edwards C. , Perry P. , Campbell G. , Stevens M.
Published: December 2007

One of the major goals of the International Association of Oil and Gas Producers (OGP) is that their helicopter operations should be as safe for the passenger as scheduled airline flying. This presents a significant challenge and requires the individual passenger risk to be reduced by an order of magnitude from current levels of safety in the offshore helicopter industry. It is estimated that the achievement of such a goal would result in the prevention of over 200 fatalities globally within the offshore industry over a 10-year period. There are a number of drivers for the offshore oil industry to achieve this goal including financial and reputational. However, more importantly, the fact that there is both a clearly identified problem and that the mechanisms exist to address the problem, mean that there is a clear moral and ethical imperative to improve helicopter safety.

In some areas of the industry work to improve safety is well advanced. As an example, twelve years ago one of the major oil companies set what were then challenging targets to reduce the 5-year average Fatal Accident Rate (FAR) for air operations within the company from a level of 15 per million flying hours to less than 5 by the year 2000. Two years ago, the companhy reviewed its goals and set intermediate targets to reduce the 10-year average FAR from 4.0 per million flying hours at the time, down to less than 2.0 by 2008 and to less than 1.0 by 2013.

This paper considers the background to the establishment of such goals and targets within the offshore industry and demonstrates how they may be achieved by progressive implementation of risk mitigation measures.

The aim of this paper is to determine how best to meet the Oil and gas Industry's helicopter risk reduction goal.
Holding Up the Leadership Mirror, Then Changing the Reflection: The "Seeing Yourself as Others See You" Tool
Authors: Bryden R. , Flin R. , Hudson P. , Vuijk M. , Van Der Graaf G. C.
Published: December 2007

Regulators, researchers and professionals in the oil and gas industry all agree on the importance of leadership commitment to HSSE. The right safety leadership is the most important factor in building a strong HSSE culture, but historically the focus has been on the workforce through traditional behavior based safety programmes. What this paper does is explain a tool Seeing Yourself As Others See You, which gives leaders personal feedback on whether they are seen to walk the talk, know what the issues are in their organization, build trust and put a priority on safety.

This tool has been developed over a number of years by the Universities of Aberdeen, Manchester and Leiden as well as the UK Step Change initiative and Shell International Exploration and Production. One component is a web-based tool, developed and supported by Leiden University, to ensure the confidentiality of the information submitted. This also allows the tool to be used by other organizations. The most important element is the follow-up coaching sessions, which is initiated by the manager, following simple and psychologically sound guidance. These sessions lead from general feedback to specific actions that positively change the way others view a manager's commitment to safety.

The results have been:

Challenging senior manager's beliefs and perceptions of themselves by confronting them with how others see them Hundreds of senior managers have been appraised, many on an annual basis A profile of leadership commitment to safety over time and obvious changes in the behavior of some managers A correlation between scores and safety performance

Based on demand from other companies the methodology described in this paper is now available to the industry through the Energy Institute1.
Robust Change Management—A Solution to Many Drilling-Related Accidents and Incidents
Authors: Houlbrook A. , Lyon A.
Published: December 2007

This paper concerns the Management of Change and the necessity for a procedure to minimize drilling related accidents and incidents. For any organisation to control its activities it is imperative that change, when it is proposed, is managed as a discreet activity to ensure a smooth transition to a new process or system simultaneously controlling risk. The paper considers why change may be necessary, how it should be managed and controlled, the impact upon a Safety Case and finally discusses accidents and incidents resulting from inadequate change control.

It is essential that the implications of proposed changes are fully considered to avoid any implementing unnecessary or ill-considered amendments to practices, procedures, equipment or the operations. Additionally, change has to be sanctioned at an appropriate level with suitable and sufficient expertise. Finally, there has to be a robust communication mechanism, both internally and externally, to ensure that modifications made are properly implemented. Some companies will even add to their audit protocols a methodology requiring study of the impact of the change and gather lessons learned for future activities.

Companies are vulnerable if change is not managed correctly and authorized at an appropriate level. Even the most basic changes to onsite plant and equipment operation or practices and procedures needs to be carefully assessed prior to implementation. As the environment in which the oil and service companies conduct their business becomes ever more rigorous, transparency and an auditable trail is essential in demonstrating the correct level of management and supervisory control. It should also be noted that in some countries, a Management of Change Procedure is an implicit legislative requirement, for example changes made to North Sea installations may have to be approved and sanctioned by the U.K. Health & Safety Executive prior to implementation, particularly if the impact is upon an installation Safety Case.

Finally consideration should be given to operational change in terms of Emergency Response. When an item of plant or equipment is in steady state operations, there is time for change management to be measured and considered. In an emergency, when the plant operation changes rapidly from steady state to emergency, staff have to be trained and ready to quickly cope with the changes that occur and potentially prevent escalation.
Modelling and Management of Annular Surface Blowouts - An SPDC Case Study
Authors: Otutu F. , Mojeed Alli , Ogunkoya A. , Ubani O. , Ezewu C. , Emesi John , Onwuzurike C. , Haug Morten , Wright John
Published: December 2007

This case study describes the planning and execution of a surface gas fire blowout control operation that resulted in re-entering, killing and abandoning a wellbore that was blowing out at the surface via the annuli "A and B" at an SPDC well blowout.

As part of the kill plan, simulations by use of the dynamic two-phase pipe flow simulator OLGA were performed. This paper presents the principles of the kill simulator and how the results were used in the design of the kill operation. A comparison with observed data and actual result are presented.

The challenges faced include, accessing the wellhead due to the raging gas fire, obsolete wellhead, vandalised wellhead entry points, and absence of top packer in the original completion are highlighted in this paper. The techniques and equipment employed, plus good teamwork, provided the necessary ingredients to divert the gas fire and gain access to the wellhead thus enabling killing, securing and partial abandonment of the well.

Introduction After a blowout, everyone wants to find the cause, prevent recurrence and understand how it was controlled. In-house papers/documentations may be written, measures are introduced to prevent another occurrence and be better prepared next time. In time, experience is lost as individuals leave and conditions become ripe for another blowout. Therefore, it is important to record, publicize, discuss and review case histories and past actions to learn about and prevent future disasters. Failure to use available information, not a lack of knowledge, usually causes and can certainly worsen disasters. This article is meant to disseminate information on an SPDC well blowout, analysis of causes, control methodology, etc., which will prove useful in educating and helping to avoid the disasters of blowout control in another well or region. Surface control operations are normally more difficult to develop due to the many possible blowout scenarios; potential escalation and unknown well response associated with intermediate control steps. For example:removing debris from Wellhead area;extinguishing fire;capping and diverting wellhead;shut-in and bullhead well dead ordynamically kill well.

At these points additional information is gained that guides the team to the course of action required to meet the next milestone (1).
Deep Well-Injection of Industrial and Hazardous Wastes in Nigeria: Prospects, Federal Regulations and the Ozoro Waste Injection Facility
Authors: Akpoborie I. A.
Published: December 2007

Existing federal regulations for the control of deep well waste injection are critically reviewed from the view point of basic hydrogeological design principles. It is shown that the Federal Environmental Protection Agency's Guidelines and Standards for Environmental Pollution Control in Nigeria (FEPA Guidelines) provide no explicit guidance for the procedure. They are therefore deficient and ineffective. On the other hand, the Environmental Guidelines and Standards for the Petroleum Industry in Nigeria (EGAS) that are published by the department of Petroleum Resources, lack precision with respect to well design, injection zone characterisation and materials specifications. Monitoring well requirements and specifications are also vague and inadequate. It also appears that several EGAS stipulations were violated at the controversial Ozoro waste injection project. These include but are not limited to the lack of an environmental impact assessment and a DPR facility permit. The fact that the Federal Ministry of Environment exonerated the project operator of any wrongdoing in spite of these violations is indicative of a lack of harmony in the enforcement of EGAS and the FEPA Guidelines. The net result of this is that when the Ozoro project was unceremoniously abandoned, closure, post closure monitoring and other essential procedures were either abandoned or not initiated. The aquifers which underlie the project area therefore remain exposed to contamination from waste that had already been injected. This issue requires immediate attention.

Because of the tremendous potential that deep well injection has for waste management in the chemical, manufacturing and petroleum industries, it is recommended that a harmonised and comprehensive guidance document for the control of deep well waste injection that takes cognisance of all hydrogeologic and hydrogeochemical considerations be developed
ADNOC Environmental Impact Severity Matrix: An Innovative Impact Rating Matrix
Authors: Alkendi M. Y.
Published: December 2007

ADNOC Environmental Impact Severity Matrix (EISM) is designed to rate the severity of environmental impacts whether from routine or accidental aspects. It takes into consideration the various contributing parameters after grouping them into 2 main axes, Duration of Impact and Impact Effect, to make the subject matrix.
The Path to Zero Flaring in ZADCO
Authors: Misellati M. M. , El Ghassnawi A.
Published: December 2007

This paper highlights the achievements made by Zakum Development Company (ZADCO) towards meeting the zero flaring strategic objective of ADNOC (Abu Dhabi National Oil Company). By the end of 2005 it is anticipated that ZADCO will have achieved 95% of the zero flaring objective.

Flare reduction technologies utilised by ZADCO are presented as part of the path to zero flaring. The path to zero flaring requires a number of technologies and approaches including initial substantial gains through gas re-injection, to later more innovative approaches such as sour gas recovery that require the careful evaluation of project economics and a range of design alternatives.

This paper features the sour gas recovery project at Zirku Island where ZADCO currently flares a predominantly acid gas stream considered to be harmful to the environment and human health. The sour gas recovery project involves the design of a compression system that avoids reducing oil production at Upper Zakum and Satah offshore facilities and eradicates the need for flaring through export of the sour gas to a sulphur recovery unit in Das Island. Increased production reliability provided the main business case for investing in environmental improvement.

The unique feature of the compression system is that it is designed to have two operating scenarios; a low pressure compression mode and a high pressure operating mode. The design of the system incorporated special features to address the problems of interaction between the high and low pressure modes of operation. These included protection, isolation, drainage and control system configuration. These features are described in detail in the paper.
Social Impact Assessment and Mitigation for a Large Pipeline Project
Authors: Pollett E. , Wyness R. A.
Published: December 2007

In this paper the Baku-Tbilisi-Ceyhan (BTC) pipeline project is used as an example to provide information on the Social Impact Assessment (SIA) process and the practical mitigation measures that were developed to alleviate, minimize or compensate for predicted impacts on affected communities during the construction program.

The BTC pipeline is 1,760 km long and was constructed in order to provide an export route for crude oil from the Caspian Sea through Azerbaijan, Georgia and Turkey to a new marine terminal constructed at the Mediterranean port of Ceyhan.

A considerable amount of social baseline information was gathered across all three countries that the pipeline crosses. Over 300 villages and 17, 700 parcels of land used by local households were affected. Social issues included: community interaction and effective consultation and disclosure; temporary land acquisition under complex land tenure systems; disturbance to local livelihoods and activities; community safety; local employment; and the potential impacts to marginalized and vulnerable groups, including ethnic minorities, women and the elderly.

The International Finance Corporation (IFC) worked closely with the pipeline sponsors in designing an oversight mechanism to address the potential social impacts of the project. Examples of mitigation measures developed included the implementation of a major public consultation and disclosure program, including continued liaison with affected communities; a transparent land acquisition and compensation program; local employment and training; community investment programs; NGO capacity building and the enhancement of development impacts through linkages with SMEs.

The project has set new regional benchmarks in transparency and the development of social mitigation practices. This paper will focus on the ‘lessons learned’ with respect to the appropriate scale of social baseline information for a project of this nature as well as provide information on the effectiveness or otherwise of the different types of mitigation practices and social standards developed for the project.
Environmental Performance in the E&P Industry—2004
Authors: Campbell J. A. , Bennett W.
Published: December 2007

In 2004, the International Association of Oil and Gas Producers (OGP) published for the first time a detailed synopsis of the environmental performance in the E&P industry. A substantial proportion of member companies provided information on five indicators: atmospheric emissions; produced water discharges; NAF drill cuttings discharges; accidental spills of oil and chemicals; and energy efficiency. Data in this report were presented as global and regional averages, normalised to production.

This performance indicator performance programme has continued and a new set of data for activities in 2004 has been produced. OGP member companies produce nearly 60% of the world's oil and about 30% of its gas. The new performance report is an opportunity to address emerging trends in environmental performance as well as factors that underpin the data.
Effect of Formations Anisotropy on Directional Tendencies of Drilling Systems
Authors: Boualleg R. , Sellami H. , Menand S. , Simon C.
Published: December 2007

Interbedded formations hard/soft or soft/hard are a major cause of borehole tortuosity. Cases history have demonstrated that this tortuosity induces a higher torque and drag, running tubular problems, stabilizers wear, pipe damage and trajectory controlling problems. In some fields, shale formations have a tendency to cause wellbore deviations to undesired directions.

The formation anisotropy modifies the rock-bit and the bit-string interactions. Those interactions have to be fully understood in order to eliminate the phenomena of tortuosity. To do so, an experimental drilling program has been carried out on a full-scale bench using various polycrystalline diamond compact (PDC) drilling bits (different gauges, profiles) in different formations (hard/soft, soft/hard with different interface angles).

Some directional tests have been also carried out in anisotropic shale at several dip angles.

Coupling a 3D bit-rock model with a 3D bottomhole assembly (BHA) model enables to predict the occurrence of tortuosity (due to the anisotropy) at small and large scales (micro and macro-tortuosity) and to evaluate feet by feet the response of all directional drilling systems (rotary, steerable motors or rotary steerable systems).

Deviations caused by formation anisotropy are separated into two phenomena. An initial deviation is caused by the rock-bit interaction. The experimental and theoretical results explain how the gauge length, bit profile, and dip angle, can affect the amplitude of this deviation. A second deviation is generated when the different stabilizers are sliding through the initial one. They can be amplified or attenuated according to the drilling system used.

The number of stabilizers and their positions, BHA characteristics and bit steerability have a considerable effect on these deviations.

A post analysis of some real drilling cases showed that, for a given drilling conditions including the formations anisotropies, it is possible to select the best drilling system minimizing the well tortuosity.
Finite Element Analysis Couples Casing and Cement Designs for HP/HT Wells in East Texas
Authors: Heathman J. , Beck F. E.
Published: December 2007

Wells drilled into the deep Bossier formations of the east Texas Hilltop Field encounter low-permeability, gas-bearing formations at over 15,000-psi pressure and 400°F temperatures. The wells require high-pressure fracture stimulations and extreme production drawdown to produce at economic rates. Wellbore temperature variations occurring between stimulation and production operations are extreme. The gases in these formations are also highly corrosive. Two of the first three wells completed in this area failed from casing collapse during completion operations or within the first few weeks of production.

Finite element analysis (FEA) modeling coupled with log-derived formation properties confirmed that the extreme stresses applied to these wells rendered previous casings and cement sheaths "under-designed." Using an approach that combined formation, casing, and cement mechanical properties into a system, the wells were redesigned. Detailed thermal and mechanical modeling of all wellbore operations resulted in redesigned casings and a cement sheath more applicable to the extreme loads being exerted. Minor changes were also implemented to the job placement procedures to lessen the loads placed on the cement sheath.

High-strength, corrosion-resistant casings and specialty cement designs were successfully used on the first two wells. Since those wells have been on production, additional wells have been drilled and completed using incrementally-simplified designs. All the wells have withstood multiple stimulations at treating pressures exceeding 14,000 psi, production test drawdowns at the perforations of over 13,000 psi, and temperature changes estimated at more than 300°F. The wells have withstood these extreme pressure and temperature changes without failure of either the casing or cement sheath.

The cement and casing designs employed have proven competent for the high-pressure, high-temperature (HPHT) conditions encountered. The successful design methodology couples well-specific casing and cement designs into a system capable of surviving the extreme pressure and temperature conditions imparted on the well during stimulation and production operations of deep, low-permeability HPHT gas sands.
Extracting Value from a Dormant Small Offshore Oil Field: The Okwori Field Case
Authors: Stenger B. A. , Guinot F. , Aubert O. , Clauss C. , Otevwemerhuere J. , Ezeukwu T. E.
Published: December 2007

Since first oil was achieved in March 2005, Addax Petroleum's Okwori field offshore Nigeria validated the deployment and illustrated the benefits of recent technical and contractual solutions for improving the economics of projects previously shelved for lack of commercial attractiveness with more traditional approaches.

Addax Petroleum's Okwori project demonstrated the feasibility of developing small and geologically complex offshore oil fields in medium water depth of 440 feet, far away from pre-existing facilities and with less than 50 millions barrels of proven and probable technical reserves (proven and probable technical) at project sanction. The Okwori oil field development went therefore a step further than the usual subsea tie-back to a larger pre-existing offshore production facility. The Okwori development concept used horizontal subsea trees flowing to a leased spread-moored Floating Production Storage and Offloading (FPSO) vessel via flexible subsea flowlines and risers.

In the subsurface, the Okwori wells combined multiple selective completions hydraulically controlled from the FPSO and expandable sand screen as sand exclusion solution; this particular combination in subsea wells for a small field marked another technological first in the offshore oil industry. Okwori leased production facilities had built-in capability for additional tie-backs such as Nda oil field development now planned for mid 2006 or for later re-deployment in other parts of the acreage depending on further exploration and appraisal drilling in the planning stage at time of writing.

Review of field operations to date highlighted a steep learning curve in the formulation of completion design, completion fluids, stimulation, sand exclusion, and bean-up/bean-down procedures.
Construction of Ultralong Wells Using a Catenary Well Profile
Authors: Aadnoy B. S. , Fabiri V. T. , Djurhuus J.
Published: December 2007

This paper presents analysis and design of ultra-long wells using a catenary well profile. Ultra long wells have a considerable economic potential as remote reservoir pockets can be drained from existing platforms. There is however, a high economic risk for these wells, many drilling issues must be resolved.

The paper presents results from a project undertaken to explore the limits and the potential for ultra-long wells. Wellbore friction is an important issue, and to analyze this a complete catenary model for design of wellpath, drill pipe loads and torque and drag forces are developed. The new model is analytically exact.

Standard build profile is compared with a catenary profile. It is shown that the catenary is not as favourable as expected due to friction in the entrance to the catenary, except that friction reduction measures can be applied over a smaller area. Application of light weight drill pipes is more important to reduce load and torque.

Both 10 km and 15 km horizontal departure wells are compared. The study shows that a 15 km horizontal departure well can be drilled with existing equipment and modern drilling units.
Large-Scale Feasibility Determination of Storing and Transporting a Cement Slurry Below Deck Under Maritime Conditions
Authors: Doherty D. , Fanguy C. , Mueller D. T.
Published: December 2007

As the search for hydrocarbons in the Gulf of Mexico extends deeper, so does the operators' need for improved technology to meet the challenges associated with these increased depths. Several operators already have wells in the planning phase with projected depths in excess of 30,000 ft. Accordingly, the casing programs will cause the well service companies to investigate alternate methods of accommodating the large cement volumes required to construct the well.

The volume required to cement one of the larger casings back to surface can exceed 20,000 sacks of cement. The conventional jack-up rigs that will be utilized to drill these deep gas wells are generally limited to less than 10,000 ft3 of bulk storage. This bulk storage is generally divided between barite, bentonite, and cement. There is an existing offshore infrastructure that is utilized daily to handle thousands of barrels of liquid drilling mud. If a liquid cement premix (LCP) slurry could be maintained in boat tanks enduring maritime conditions for extended periods of time, it would then be possible to perform a 30,000+-sack cement job from an offshore supply vessel.

In order for the LCP cement slurry to be considered as a viable alternative to conventional cementing technology, it would be necessary to determine: Is the agitation system in the liquid mud tanks sufficient to maintain large quantities of premixed cement slurry?Can slurry maintenance be performed on the slurry while it is in the liquid mud tanks?What are the personnel requirements for liquid slurry maintenance while at sea?Can the boat transfer liquid cement at a high enough rate to meet the job requirements?Could the density of the original premixed slurry be increased and/or decreased in the boat tanks?

This paper will outline the 10-day slurry stability test that was undertaken aboard an offshore supply vessel. This test was a large scale field trial, under anticipated storage conditions, of a 600-bbl quantity of pre-mixed cement slurry stored in the liquid mud tanks of a working offshore supply vessel. This paper will also discuss the testing results and conclusions drawn from the field trial.
Community Based HSE Projects—Eni NAOC Contribution to Niger Delta Development
Authors: Tavolini E. , Onyia J. , D'Ippolito D.
Published: December 2007

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

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

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

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

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

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

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

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

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.