bluuebunny/crossref_metadata_2025_split huggingface dataset:
Robust Change Management—A Solution to Many Drilling-Related Accidents and Incidents
Authors: Houlbrook A. , Lyon A. 
Published: December 2007

Abstract
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

Abstract
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

ABSTRACT
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
The Path to Zero Flaring in ZADCO
Authors: Misellati M. M. , El Ghassnawi A. 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.