bluuebunny/crossref_metadata_2025 huggingface dataset:
Flooding by High-Concentration Polymer Doubled Oil Recovery of Common Polymer on Field Test with 20% Closed to the Result of Laboratory Test in Daqing
Authors: Liu Bing , Sun Xiuzhi , Wang Kun , Xu Hong , Liu Qi , Liu Xin , Song Shuling
Published: December 2007

Common polymer flooding on-site tests and industrialized application indicates that conventional polymer flooding gives about a 10% more oil recovery than waterflood, with an ultimate recovery of 51% OOIP. But, because the existence of high permeable zones, this sometimes makes polymer flooding insufficient or ineffective in the reservoir. In some polymer flooding producers, after polymer is breakthrough, water-cut increases rapidly, it adversely affects polymer flooding, resulting in on-site enhancing recovery greatly lower than 20% of laboratory estimates.

In 2002, on the basis of high concentration polymerflooding study in lab, we perform high concentration polymer flooding on-site. By optimizing slug combination and adequate monitoring and analyses, water-cut is greatly decreased, with a decrease percentage of 14.5, this improves polymer flooding development effect. The field test data shows, that high concentration polymer flooding in beginning, recovery has given 4.2% higher than that of conventional polymer flooding by Dec. 2005; and flooded in later stage recovers 3% more oil than conventional method, this indicate that the result of high concentration polymer flooding in initial stages is better than in later stage.

Polymer flooding monitoring and simulation technology predicts that 19.8% more oil can be recovered than water flooding, with a production degree of 61% OOIP. On-site high concentration polymer flooding recovery is two times of the conventional polymer.
New Innovative Wireline Jar Adds Significant Value by Reducing Fishing Cost
Authors: Evans Robert W. , Brame James Chester , Rose Lawrence C. , Dorffer Daniel
Published: December 2007

This paper discusses a new, innovative tool, namely a hydraulic jar with a mechanical lock developed to run on wireline cable. The discussion addresses (1) the role and value of wireline jars in electric line operations, (2) technical features of the new wireline jar system with comments on its operation, and (3) a brief review of several of the many successful field applications.

Getting stuck during a logging operation can add significant cost to a well. The new wireline jar has proven to be remarkably effective in freeing stuck wireline tools and preventing costly fishing operations. Freeing the tools also provides the opportunity to complete the required data acquisition as the instruments have historically not been damaged by jarring. In addition, the use of the wireline jarring method described in this paper allows operators to run relatively inexpensive free-fall wireline tools in areas that previously ― due to sticking problems ― have gone straight to drill-pipe-conveyed operations or logging while drilling (LWD) methods.

A multi-conductor jar, called the LockJar®, has been in use for more than four years. The jarring system utilizes a proprietary-design LockJar and Enhancer, both of which remain passive until such time as they are needed. The LockJar can be pulled, without triggering, as hard as desired for durations shorter than the tool's time delay. Slacking off the string resets the LockJar so that it can be pulled again. Experience with this new technology has also led to discovery of valuable best practices for handling stuck tools, which has increased the number of freed tool strings. Among these best practices is the use of properly placed standoffs, particularly in inclined sections of wellbores.

Experience with this new technology began in the GOM but the technology has quickly spread around the world to locations that experience problems with sticking during logging. In the GOM, several examples can be cited including a job where the LockJar was activated over 20 times in six different intervals; and still the well was successfully logged. This well was the very first in the field that was logged without a fishing job.

Successes described in this paper include an example from the US Rockies and in Brazil and other international locations, such as West Africa, where the LockJar also freed tools on their very first run.
Latest Generation Horizontal Well Placement Technology Helps Maximize Production in Deep Water Turbidite Reservoirs
Authors: Altman Raphael , Ferraris Paolo , Filardi Fabricio
Published: December 2007

This account describes how advanced well placement technology helped to optimize horizontal well position and maximize hydrocarbon production in deep water turbidite reservoirs. The deep reading directional electromagnetic tool, a latest-generation LWD (Logging While Drilling) measurement, was the technology differentiator for optimizing well placement in a number of deep water horizontal wells.

The new directional measurement is highly sensitive to reservoir boundaries and therefore gives early warning of conditions requiring steering adjustments while drilling horizontal wells, maximizing well position in the reservoir. This paper shows how thin oil rims, faulted reservoirs and those with highly variable structure were able to be developed more efficiently. By reducing uncertainties about the reservoir, the new technology helped optimize production, eliminate sidetracks and minimize well construction cost and risk.

One of the main challenges of maintaining a horizontal wellbore inside a thin hydrocarbon bed is the uncertainty of formation dip. Inside a hydrocarbon bed, real time resistivity images often yield dips that are more representative of stratigraphic features rather than structure defining reservoir boundaries (from surrounding, conductive shale beds). The deep-reading azimuthal electromagnetic measurement helped in early detection of neighboring conductive beds, and the distance to these beds. This ensured that the wellbore was drilled parallel to the structure and inside the ‘sweet spot’ away from non-productive layers.

As reservoirs become more challenging to develop, the use of advanced technology often helps minimize risk. When fields are developed with horizontal wells, it is desirable to maximize well position inside the reservoir layer since the rate of increase in hydrocarbon production increases as horizontal length in the reservoir increases. We show an example of how advanced well placement technology was successful in doubling hydrocarbon production rate compared with wells in the same field drilled with conventional technology.
Use of Conductivity-Enhancement Material To Sustain Productivity in Hydraulic Fractured Wells: Northern Mexico Cases
Authors: Soriano Duverney J. Eduardo , Garcia Raul , Rivera Juan Galvan , Carrillo Alejandro Barrera
Published: December 2007

Rapid production decline rate is associated with the loss of fracture conductivity after hydraulic fracture stimulation. This loss of conductivity has often been attributed to the migration of formation fines into the proppant pack or the generation of fines derived from proppant crushing. Surface modification agents were introduced in the stimulation market around 1997, and according to literature published since then, these materials have been helping to sustain fracture conductivity, and subsequently, mitigating production decline rates.

This paper presents long-term results from the use of these materials in hydraulic fracture stimulation operations in the Burgos Basin in northern Mexico; results from offset wells are also presented for correlation and comparison. Production from this basin comes from low-permeability sandstones normally considered tight gas formations.
Impacts From Fractures on Oil-Recovery Mechanisms in Carbonate Rocks at Oil-Wet and Water-Wet Conditions—Visualizing Fluid Flow Across Fractures With MRI
Authors: Fernø M. A. , Ersland G. , Haugen Å. , Johannesen E. , Graue A. , Stevens J. , Howard J.
Published: December 2007

The fracture/matrix transfer and fluid flow behavior in fractured carbonate rock was experimentally investigated using magnetic resonance imaging (MRI). Viscous oil-water displacements in stacked carbonate core plugs were investigated at wettability conditions ranging from strongly water-wet to moderately oil-wet. The impact of wettability and was investigated in a series of flooding experiments. The objective was to determine the impacts on fluid flow from different types of fractures at various wettability conditions. A general-purpose commercial core analysis simulator was used to simulate the flood experiments and to perform a parameter sensitivity study. The results demonstrated how capillary continuity across open fractures may be obtained when wetting phase bridges were established. A viscous component over the open fractures was provided when the wetting preference between the injected fluid and the rock surface allowed the formation of stable wetting phase bridges. The combination of high spatial resolution imaging and rapid data acquisition revealed how the transport mechanisms for oil and water were governed by the wetting affinity between the rock surface and the fluids in the fracture; both at moderately water wet conditions and at moderately oil wet conditions.
Mobile Support Center Provides Cost-Effective Alternative to Dedicated Facility
Authors: Clyde Robert , Akinniranye Goke , Goobie Roger , Alvarez Carmen Elena , Gorgone Ignacio
Published: December 2007

Drilling operators worldwide face increasingly complex and costly drilling challenges. In addition to difficult and sometimes harsh downhole environments, the driller is also faced with a dramatic increase in the quantity and quality of information available to optimize recovery. In many of these situations, there is little or no room for error and the cost of nonproductive time (NPT) due to a poor or less informed decision can significantly increase the final cost per barrel to the consumer.

Advances in cost-effective satellite communication and the application of compression technology have removed the bandwidth limitation, and Internet transfer of continuous high-volume real-time data between the offshore installation and shore-based operations is almost seamless.

With the current shortage of skilled personnel, most major oil and gas companies are exploring remote Operation Support Centers to support their real-time E&P business processes. With a combination of infrastructure, technology, services and processes, these support centers are consolidating their expertise in a collaborative environment so that informed real-time decisions can be made to improve drilling processes and reduce costs.

The economic justification to management and partners for investing and building support centers is clear, but it is necessary to scale the effort and capital expenditure for support centers to each specific drilling operation. This paper describes the concept of low-cost remote support centers that have been used successfully in the Gulf of Mexico, and land drilling projects on the Alaska North Slope and in northern Mexico.

A successful support center must quickly turn real-time data into useful information displayed with minimum latency in a format benefiting decision makers. This depends on the skill and experience of each participating engineer and the quality of the software answer products in this surveillance environment. This paper describes advanced real-time software answer products that take raw drilling data and filter it into different rig states, automatically generating logical outputs.
High-Strength Threaded and Coupled Connectors for Dynamic Riser Applications
Authors: Shilling R. , Payne M. L. , Massaglia J. , Sches C. , Leyer J. , Pinto J.
Published: December 2007

In the last 5 years, a number of key advances have been made with threaded and coupled (T&C) risers. These advances together with high strength steels have enabled these products to reach parity with the current standard of weld-on connectors. The T&C riser concept demonstrates the same reliability, field proven history and high fatigue performance. This concept of connectors and engineered materials up to 125ksi, allow for significant weight savings on the riser system and platform construction. To meet the Global Energy needs now, the industry must move to deeper water and higher fatigue. Thus a new generation of connectors, fully optimized for fatigue, has been designed for inner and outer production riser applications.

These connections reach best-in-class fatigue performance and include innovative fatigue compliant sealing systems. The large number of full scale fatigue test results increases confidence to such a level that fatigue trends and influencing parameters now help to refine the qualification programs. This new standard will also allow the industry to look for new generations of heavy wall riser connectors for xHPHT, flow line, and SCR applications.

The purpose of this paper is to highlight the knowledge that has been accumulated in various fatigue enhancement techniques and the continuous improvement of analysis capabilities.
Pressure Losses of Non-Newtonian Fluids in Drilling Operations
Authors: Demirdal Barkim , Cunha J. C.
Published: December 2007

Precise estimation of annular pressure losses is essential in drilling and well completion operations to control formation pressures and optimize drilling and completion fluids' hydraulic programs. Without accurate estimation of annular pressure losses it is possible to face serious problems that would yield interruption in drilling operation and sometimes lead to abandonment of the well. While annular pressure loss estimations are critical, determination of pressure losses associated with flow of Non-Newtonian fluids is challenging. Many investigators proposed different equivalent diameter concepts to provide a similarity between pipe and annular flow.

In this study we have investigated the coupling effects of rheological model and equivalent diameter definition on pressure losses using three rheological models (Bingham Plastic, Power Law and Yield Power Law) together with four different equivalent diameter definitions. Effects of inner/outer radius ratios and flow rate on pressure losses determined using different rheological model and equivalent diameter pairs are analyzed using an onshore well and an offshore well. The differences in pressure losses using different pairs for the cases of onshore and offshore wells are shown. The study provides detailed analysis on how severely the annular pressure losses varies once rheological model and equivalent diameter definitions are changed for different operating conditions.
An Efficient Horizontal Openhole Multistage Fracturing and Completion System
Authors: Seale R.
Published: December 2007

Over the last two decades many developments have enabled accelerated growth in horizontal drilling. Drilling technologies have pioneered these advancements, with current technology capable of drilling thousands of feet through a thinly bedded hydrocarbon reservoir. Completion advancements designed for extended horizontal wellbores have also advanced, albeit at a slower pace. Initially horizontal drilling was limited to naturally fractured reservoirs with simple open hole or slotted liner completions. This was due primarily to the ability of the reservoir to flow economically without the need for stimulation. Reservoirs requiring stimulation were initially not candidates for horizontal drilling. Developments in completion technology specific for horizontal wells have broadened the reservoirs where horizontal wells can be effectively stimulated.

When drilling a horizontal well, there are two completion options. First, the horizontal can be completed open hole, or with slotted/perforated liner. Effective stimulation along the horizontal wellbore is impossible. The second completion system requires cementing the production liner and running multiple isolation systems to effectively treat different sections of the wellbore. Multiple coiled tubing trips and multiple rig up and down of the stimulation equipment are required. These multi-stage horizontal completions take weeks to complete at high costs and elevated risks. Ultimately, the high completion costs or the lack of production due to ineffective stimulation make many reservoirs uneconomical to exploit.

This paper will discuss a new open hole completion system run as part of the production liner, does not require cementing and provides mechanical diversion at specified intervals, thus allowing fracturing and stimulations to be effectively pumped to their targeted zone. Details of the engineering design and testing will be specified, with elaboration on the applications and case histories were these systems have been successfully deployed. The case histories will detail the operational efficiencies of the system in conjunction with the enhanced production realized.
Analysis of Capillary, Gravity and Viscous Forces Effects in Oil/Water Displacement
Authors: Rosado-Vázquez Francisco J. , Rangel-German Edgar R. , Rodríguez-de la Garza Fernando
Published: December 2007

Reservoir performance during waterflooding is important to reservoir engineers. Analytical and semi-analytical flow models with different assumptions have been presented and used widely to describe the flow dynamics of such a process. Most assume that one of the terms, typically capillary forces, can be neglected or considered constant diffusion coefficients, so the simplified diffusive-convective type of flow equations can be solved analytically or by numerical methods. Obtaining analytical or semi-analytical solutions to non-linear diffusive-convective flow equations, including capillary, gravity and viscous forces simultaneously, has been a challenge.

This paper presents a theoretical study of the effects that controlling flow parameters have on saturation profiles and breakthrough time during oil recovery by waterflooding. A mathematical non-linear diffusive-convective type model for immiscible oil-water displacement in one-dimensional vertical homogeneous porous media considering the three chief forces (capillary, gravity and viscous) is derived and solved numerically by using a finite-difference formulation with fully implicit scheme in time and central differences in space.

Dimensionless equations are written so that any of the three forces can be investigated independently; capillary and gravity forces can be "turned on or off." The effects of varying fluid viscosity, injection flow rate, system length or wettability, for both displacing and displaced fluids, can be understood thoroughly. The flow model is versatile enough that it allows for variations of the shape of the relative permeability and capillary pressure functions. The impact of these functions in the driving forces and on oil recovery is analyzed.

The contribution of each of the forces to the dimensionless water velocity and its impact on oil recovery was studied in four flow cases: viscous, viscous-gravity, viscous-capillary and viscous-gravity-capillary; all possible flow cases in water injection problems were considered. Graphical results are discussed.
Optimal Practices To Remediate and Control Fines Migration in Inland-Water Wells in the Maracaibo Basin, West Venezuela
Authors: Chávez N. , Colmenares O. , Peña A. , Fuenmayor A. , de Sousa V. , Miquilena E. , Maiz O. , Escobar J.
Published: December 2007

This paper summarizes the following aspects of a comprehensive program intended to develop optimal practices for the stimulation of wells in the Ceuta field, a developing area located in Lake Maracaibo, West Venezuela: lab testing to diagnose formation damage mechanisms and to qualify proposed treatments; operational practices including injection sequence, treating volumes for optimal radial penetration and diversion techniques for uniform placement; recommended safety and environmental practices.

Also, detailed examples of treatments performed in six inland-water wells in the Ceuta, Area 8 South Central area within this field are provided. The average production rate for these wells before the implementation of these practices was 419 BOPD. The implementation of the guidelines provided in this paper resulted in an average post-production rate of 2100 BOPD with a twelve-month average decline rate of 1.6 BOPD.

The enhanced methodology has been implemented with success in other fields in the Maracaibo Lake area known as CentroLago, Lagotreco and Lagocinco. Results from treatments in these areas are also summarized and discussed.
A Study of Normal Slug Flow in an Offshore Production Facility With a Large-Diameter Flowline
Authors: Vázquez E. Guzmán , Fairuzov Y. V.
Published: December 2007

A theoretical and experimental study of a normal (hydrodynamic) slug flow in a pipeline-riser pipe system is presented in this paper. Experimental flow visualization revealed that long hydrodynamic slugs generated in the pipeline do not dissipate in the riser pipe. It was shown that slug dynamics in the riser pipe is controlled by two phenomena: the gravitational forces and the compression of gas in the trailing bubble. It was found that slugs can accelerate in the riser to a velocity more than five times exceeding the average slug front velocity in the flowline. The results obtained can be used to define operating strategies for offshore production facilities with large diameter flowlines.
Solid Expandables Repair Prolific Subsea Gas Producer
Authors: Velden Mark Van De , Funiss Tony , Stewart Kevin A.
Published: December 2007

A working window of opportunity only presents itself from April to mid-September in the turbulent Atlantic waters off the northwest coast of Ireland. When this window opened in Spring 2006, Shell E & P Ireland Ltd began operations to evaluate newly acquired assets in the Corrib fielddry-gas subsea development. Prior to acquisition, five wells had been placed in suspension, pending construction of the necessary subsea and onshore infrastructure. Shell had previously determined that only three wells were viable candidates for completion during the current season and commenced operations when the S711 semi-submersible arrived on location in April. The clock started ticking on favorable weather and time quickly became a crucial constraint issue. The project hit a critical mark when a leak was discovered in the 9-5/8 in. production casing on one of the early wells entered.

With time running out, Shell approached Enventure to engineer a practical solution that was required within a period of six weeks. Possible solutions for recovery were identified and analyzed before the project management team decided on using solid expandable technology. The solution for this well needed to deliver a production casing string that effectively sealed off the hole. To accomplish this requirement with expandable tubulars, Shell decided to use the Enventure system elastomers for the gas-tight integrity, which required qualification. In approximately six weeks, Enventure and Shell planned and implemented the appropriate tests, coordinated logistical maneuvers to expedite expansions to create the test specimen for qualification and successfully installed the actual system in the production well.

This paper will discuss the process used to bring the project to fruition within a tight timeframe. Details will include issues considered, ramifications of possible options, challenges of the operating conditions and circumstances and content and results of the qualification program. This paper will also discuss the philosophical approach of generating a workflow to successfully achieve the stated goals in a short amount of time.
History Matching With an Ensemble Kalman Filter and Discrete Cosine Parameterization
Authors: Jafarpour B. , McLaughlin D. B.
Published: December 2007

History matching of large hydrocarbon reservoirs is challenging due to several reasons including: 1) Scarcity of available measurements relative to the number of unknowns, leading to an ill-posed inverse problem; 2) Computational effort required for large reservoir problems; 3) The need to insure that solutions are geologically realistic. All of these problems can be helped by using algorithms that rely on efficient and parsimonious descriptions (or parameterizations) of reservoir properties. This paper combines a novel parameterization approach, the discrete cosine transform, with a recursive history matching technique, the ensemble Kalman filter, to provide efficient estimation of unknown geological properties in large reservoirs. The application and generality of this approach is demonstrated using two waterflooding experiments characterized by different types of geological variability.
Modeling a Finite-Length Sucker Rod Using the Semi-Infinite Wave Equation and a Proof to Gibbs’ Conjecture
Authors: DaCunha J. J. , Gibbs S. G.
Published: December 2007

In this paper, we study semi-infinite spatial domain wave equations modeling the real world problem of longitudinal waves propagating along a finite length long slender homogeneous elastic rod. To conclude, we provide a rigorous, yet elegant proof to Gibbs’ Theorem and illustrate its validity with an existing well.
Optimization of Fractured-Well Performance of Horizontal Gas Wells
Authors: Magalhaes Fellipe , Zhu D. , Amini Shahram , Valko P.
Published: December 2007

Horizontal well technology has been widely used in developing gas fields. Very commonly, these wells are hydraulically fractured to improve productivity in low permeability reservoirs. A previously developed method, the Distributed Volumetric Source method (DVS), was applied to horizontal gas wells with or without fractures to predict well performance. The method is flexible and can be easily applied. The method provides an effective tool to evaluate horizontal well design and well stimulation design for gas wells.

In this paper, we conducted a well performance study by applying the DVS method to typical gas formations in East Texas Basin, San Juan Basin, and Appalachian Basin.. The objective is to determine the best practice to produce from horizontal gas wells. With the transient flow feature of the DVS method, well placement for multiple horizontal wells in a defined drainage area can be studied, and the limit of well spacing and wellbore length is identified. For fractured wells, well performance of a single fracture and multiple fractures are compared, and the effect of the number of fractures on productivity of the well is presented. Realizing that reservoir permeability and anisotropy ratio are the critical parameters in developing low-permeability gas fields, the effect of permeability on well performance, well placement and fracture treatment design is addressed in the paper.
Strategy for Managing Environmental Liabilities in an Onshore Oil Field
Authors: Austin D. G.
Published: December 2007

Environmental liabilities for an onshore oil field include facility abandonment, well plug and abandonment, environmental investigation and remediation, and land restoration. Having a systematic approach for discharging these liabilities offers prudent fiscal management and business planning, environmental compliance assurance, improvement of company image, minimization of legal claims, and ability to secure resources to implement work.

In 2003, Chevron began to develop a strategy to manage the liability associated with their CPI Sumatra Operations. The first step was to understand the magnitude of the liability by conducting a Liability Inventory. Next, the liabilities were prioritized based on safety, environmental, security, and operational considerations. Cost estimates were completed and an annual plan developed to discharge the liabilities over a selected time period. For larger remediation projects, decision and risk analysis was employed to determine the preferred timing for execution accounting for the time value of money, likelihood of incidents and the consequences if those incidents occurred. Management of liability for facility abandonment also involves asset write off so that integration of this financial process is required.

Technologies and procedures were developed for implementation, focusing on safety and cost effectiveness through standardization. Methods were developed for management of wastes generated which included liquid hydrocarbon wastes, contaminated soils, insulation waste, scrap equipment and piping, and concrete foundations.

Management of environmental liability is an evergreen process. At CPI, we have found that review is necessary twice per year to keep up with all the changes due to new information from environmental site assessments, schedule adjustments usually due to resource limitations, and priority changes due to public pressure or claims.

The paper will describe the strategy, processes, and methods in more detail. This approach may be applied at almost any on-plot facility or off-plot well field to plan for management of liability.
Reconciling Subsurface Uncertainty With the Appropriate Well Design Using the Mechanical Earth Model (MEM) Approach
Authors: Goodman H. E. , Connolly P.
Published: December 2007

The involvement of the well engineer (WE) competency from the earliest phases of exploration is reaping economic benefit for major capital projects (single wells costing at least $25,000,000 US). As the geological and geophysical modeling work of the Explorationists matures and the subsurface picture becomes clearer, the appropriate well design flexibility is being achieved using Mechanical Earth Model (MEM) technology. This approach to well planning is particularly beneficial for deepwater exploration.

For deepwater subsalt plays, the capital outlays are immense, with single wells costing up to $100,000,000 US. For these projects, MEM technology has been found to be extremely valuable, particularly in characterizing drilling risks associated with well exit points below salt where in-situ stress perturbations can occur. These stress perturbations are being reliably mapped using MEM techniques and the consequences to borehole stability addressed. An example of principal stress rotation gleaned from a deepwater MEM and the consequences to borehole stability is summarized in this paper.
Operationalising HSE Cases in Asia Pacific
Authors: Peake D. M. , Sahari Y.
Published: December 2007

Implemented post Piper Alpha, HSE Cases have become a crucial document for demonstrating the adequacy of the management of Major Accident Hazards (MAH). However whilst serving the needs of Regulators and Company Auditors, there has been increasing dissatisfaction with the value they add to Operations personnel even when translated from "Design Cases" to "Operations Cases".

A survey amongst Asia Pacific OIM's yielded common concerns with the current Cases, independent of asset type and operating area (including Regulatory environment), among them:Lack of transparency between daily operations and a Case that "sits on a shelf".Change management.Difficulty in easily understanding/comprehending major hazards.Unwieldy documents that are a "catch-all" for any Health, Safety, or Environmental related issue.Remedial actions that are seldom closed.

A closely related issue is Technical Integrity on aging platforms and the tolerability of equipment state with HSE Cases that dont provide any tangible/practical guidance on ‘acceptability’ of barriers.

To address these concerns Shell Exploration & Production Asia-Pacific (Shell EPA) is implementing a program to "Operationalise" HSE Cases. At the core of the program is the objective to refocus HSE Cases on Major Hazards and provide a roadmap to Company systems (centered on Technical Integrity) that will provide effective barriers during the operational phase.

No element of the program is ‘revolutionary’ but in its entirety provides a cohesive and transparent means of communicating Major Hazards to Operations personnel and providing them a tool to demonstrate that they have the right systems in place to maintain barriers. The Cases are highly focused on Operator's needs, and draws in global best practice from within the Company and Industry.

This paper outlines the issues leading up to revamp of Cases, framing of the program and core issues, selected way forward on Case content, elements required for success, and roll-out/accountability requirements.
Building a Sustainable Proactive Intervention Culture among Workforce—I Care for Your Safety: The Journey by Shell E&P in Asia Pacific
Authors: Koh Richard , King Kai Hii
Published: December 2007

This paper describes Shell EPA (Shell Exploration & Production in Asia Pacific) efforts and strategies to achieve a step change in safety performance by building a sustainable "Proactive Intervention Culture" (PIC) among her workforce, which will intrinsically motivate people to intervene in unsafe acts and situations because they believe in it, rather than because they are being forced or told to.

The paper details the planning and development of the PIC training programme, implementation plan and progress to date by Shell EPA to build a sustainable proactive safety culture among staff and contractors.
Use of a computer simulation to assess Hazard and Risk perception
Authors: Lang Kenneth , Breitsprecher Kathryn , McGrath Tim
Published: December 2007

Hazard identification and risk assessment are at the core of an effective health and safety system. Despite this fundamental, during incident and accident investigation risk assessment processes are sometimes not used effectively and found to be deficient.

The challenge facing both individuals and organizations is that individual risk tolerance and perception of hazards varies significantly according to a host of factors including social and personal values as well as prior experience and beliefs. To truly drive a reduction in incidents a variety of methods need to be used to ensure that workers are aware of the hazards, the risks and the consequences of action/inaction. This will also enable individuals to become aware of their own risk perception and how other factors can affect ones acceptance of risk thereby changing their risk taking behaviour.

This paper presents an innovative method measuring task based risk perception in the form of a computer virtual reality simulation. While not widely used in the oil and gas industry the application of a computer simulation has been valuable in other contexts, such as testing of risk perception in drivers and pilots. This simulation is based on the physical location of a marine based rig during routine rig operations. This simulation therefore gives an important insight into the hazard identification, risk evaluation and risk awareness in the offshore context. Experiences from the application of the simulator are shared and some of the methods of reinforcing the lessons learnt are also discussed.

Possible further developments are considered and in particular how this simulation can be used in the context of both new employees with lack of experience, and experienced staff who may be complacent, as the both groups are vulnerable.
Detecting Ultra-small Leaks With Ultrasonic Leak Detection-Case Histories From the North Slope, Alaska
Authors: Julian J. Y. , King G. E. , Johns J. E. , Sack J. K. , Robertson D. B.
Published: December 2007

A new ultrasonic leak detection logging tool conveyed on electric line, and recently on wireline in memory mode, has been introduced which can detect leaks as small as 1/2 cup per minute. This revolutionary tool has been used to accurately identify leaks in tubing and behind pipe. Wells that otherwise would immediately be slated for a rig workover (RWO) have been repaired with non-rig solutions.

Ultrasound energy has very rapid attenuation and the ability to transmit through various media and behind pipe. These attributes allow pinpoint accuracy for leaks as small as 0.0024 gallons per minute (gpm). The tool incorporates data acquisition equipment and filtering algorithms which allow continuous logging. The technology is far superior to old-style noise logs which require time consuming stationary counts.

To date, BP has run 21 ultrasonic leak detection logs in Alaska fields with an 81% success rate. The recent ability of this tool to be conveyed in memory mode has opened up additional logging opportunities. This has led to the development of a new technique using nitrogen to identify wells that leak only to gas.

Application of this tool has great significance for any operator concerned with well integrity, and particularly, in areas where rig workovers are expensive including remote, offshore, and arctic locations.
Environmental Due Diligence for International Finance of Major Oil and Gas Projects
Authors: Jeter J. L.
Published: December 2007

The European Bank for Reconstruction and Development was founded in 1991 to assist transition in the former communist countries of Central and Eastern Europe towards a free market economy. In line with EBRD Natural Resources Operations Policy (1), over the last few years we have been involved on several large oil and gas development projects in our region of operations. The environmental due diligence on these projects is a significant task, requiring extensive resources by the project sponsor as well as the potential lenders. Complexities in the process are highlighted when there are multiple potential lenders involved with different mandates, internal standards and policy requirements. The EBRD is required to promote in the full range of its activities environmentally sound and sustainable development. As such, our Environmental Policy (2) requires that our projects meet good international environmental practice. This includes applicable national environmental standards and pertinent environmental standards of the European Union.

In our recent experience, project sponsors typically first complete their Environmental Impact Assessment (EIA) required for local permitting/project approval. Once this document has been approved locally and the project has been approved by pertinent authorities, the project sponsor typically uses some form of this document (or data contained therein) as the EIA for financing. While there is merit in this approach, recent experience highlights a number of issues that could be considered to streamline this process in the future. These issues can be grouped under the following headings:Scoping and EIA ProcessLender Engagement and Document CompletionDisclosure ProcessPost Signing and Monitoring

This paper presents a review of the lessons learned based on EBRD involvement on the due diligence of two recent "mega" projects in the oil and gas sector. While this paper clearly will not identify all potential problematic issues that could arise during environmental due diligence for finance, consideration of these factors could help streamline future project finance deals.
Environmentally Safe Waste Disposal: The Integration of Cuttings Collection, Transport, and Reinjection
Authors: Alba A. , Fragachan F. , Ovalle A. , Shokanov T.
Published: December 2007

The development of new oilfield technologies to explore such remote areas as deep waters and environmentally sensitive locations brings with it increased emphasis on protecting the natural resources of the drilling area. Accordingly, many regulatory agencies demanding zero discharge policies require all generated wastes to be disposed in a responsible manner. Such process requires the adequate management of wastes generated during drilling operations including cuttings, excess drilling fluid, contaminated rainwater, produced water, scale, produced sand, and even production and cleanup waste. Old practices involve temporary box storage and hauling of the waste products to a final disposal site. Often, these sites are several kilometers away from the generation source, creating not only liabilities for the operating company but also environmental risks such as accidental spills, gas emissions and eventually high operating costs.

Over the years, waste management technologies have evolved to address environmental solutions in the most efficient and cost-effective processes. As such, Cutting Re-Injection (CRI) nowadays is considered top-of-the line technology for the final disposal of drilling wastes through sub-surface injection into an engineered-designated formation where wastes are permanently contained. Transporting the wastes to the final disposal well poses a challenge in large development fields, where the most cost-effective solution is often to drill a dedicated injector and convey all produced wastes to the site.

This paper addresses the success of integrating methodologies for containing, handling, and transporting drill cuttings from several drill sites to a unique CRI well, where wastes are injected for final and responsible disposal. Case histories of several sites around the world are presented as they used different process configurations to achieve the common final objective: a cost-effective and environmentally friendly solution for waste management.
Marine Subcontractor Safety Management
Authors: Charusalaipong P. , Yimkijboriharn T.
Published: December 2007

Historically, marine vessel support has played an important role in the offshore E & P industries. Especially, present increased of E & P activities but less number of ships in the market. The increased activity has an added on effect to marine vessel workload i.e. more frequent cargo trips with less time in port. Also marine vessel stay out longer at sea, subsequently, crew has less relaxation time and ship has less maintenance time. This will eventually resulted in a breakdown of ship and degradation of crew morale. As a consequence, the marine operation near miss incident trends has been increasing. To counteract this trend, it requires a close scrutiny and well-manage program to divert this marine vessel operating degradation.

Marine Subcontractor management is considered a paramount in achieving Health, Safety and Environment Objective and ensuring safe marine operation. To achieve these goals, a recent company standard was implemented to ensure marine operation safety and manage marine vessels as per the contractual terms and conditions and some satisfactory outcome has initially materialized i.e. less marine near miss incidents.
Analysis of Carbon Capture and Storage Cost Supply Curves for the UK
Authors: Hare Phil
Published: December 2007

This paper reports modeling of economic supply curves of Carbon Capture and Storage over future time horizons and examines how the economics change as the volume of deployment increases – ie to develop a cost supply curve for all the major static emission sources on the UK mainland.

We consider the supply curves for both the sources and storage sinks as well as when combined by a transport network. For the composite curve, the market implications of the likely economics, the context of the EU ETS and other market considerations are considered.

A reasonable basecase suggests that up to 100mt pa of carbon dioxide could be stored at prices below £30/tonne before any carbon allowance income is included.

The author is grateful for support in developing this paper from Barry Ladbrook of Pöyry Energy Consulting, Ewa Kmietowicz, George Marsh and Jo Rowbotham of the DTI, Sam Holloway of the BGS and Isabelle McKenzie and Mark McKenzie of Equilibrium Consulting. The project was supported by the Department of Trade and Industry.
The Rhum Field a Successful HP/HT Gas Subsea Development (Case History)
Authors: Brown Alastair , Farrow Chris , Cowie Jim
Published: December 2007

The Rhum Field is a high pressure / high temperature gas accumulation in the North Viking Graben with an estimated GIIP volume of 1Tcf. The P198 licence was awarded to BP and the Iranian Oil Company (U.K.) Limited (50/50) in 1972 and is located approximately 380km north-east of Aberdeen in 115metre water depth. First gas was in December 2005 with production of 250 million cubic feet per day from 1 new development well and the re-completion of the 2000 appraisal well. The field produces via a sub sea tie-back scheme to the Bruce Field platform, 43 kilometres to the south.

Rhum was discovered in 1977 with well 3/29–2, which penetrated a thick gas bearing sequence of Upper Jurassic turbidites. This well was plugged and abandoned without testing, owing to the difficulty in testing high-pressure wells with the tools available at the time. Twenty-three years later, in 2000, appraisal well 3/29a-4 was drilled and extensively cored and logged. Finally, in 2004/5, the field was developed with 2 new wells as part of a project that has now brought the 27 year old discovery successfully into production.

Production is through natural depletion with minimum expected aquifer support. The Field Development Plan provides for the completion of three development wells, including re-completion of the 3/29a-4 well. The sub-sea wells are individually tied back to the Rhum sub-sea manifold and from there connected back to Bruce via a single 16", pipe-in-pipe insulated flow-line, which is trenched and backfilled. The Bruce Platform processes the Rhum gas for onward transportation to St Fergus via the Frigg pipeline.

The Rhum Project used many new technologies in an innovative way in order to overcome the harsh and challenging environment of a North Sea HP/PT subsea gas development.

Location

The Rhum Field, discovered in 1977, is located in the Northern North Sea, 380 km north east of Aberdeen and 43 km north of the Bruce platform. The field contains approximately 1 Tcf (GIIP) of high pressure (12,500 psi), high termperature (300 degrees Fahrenheit), dry gas, and is owned by BP (50%), the Operator and the Iranian Oil Company (IOC) UK (50%).

The Rhum field has an aerial extent of approximately 25 square kms and is located in Blocks 3/24b, 3/29a, 3/29b and 3/29d, Figure 1.
Land Transport Safety Management Practice of Crude Evacuation, Greater S1 Assets, PTT E&P
Authors: Dhitavara Vitaya
Published: December 2007

Following a disastrous year of road accidents in 1998, including a contractor fatality and several third party fatalities the Company has investigated alternative crude evacuation options. However the crude evacuation by road remains the optimum solution. To reduce the associated risks with road transport of crude to As Low As Reasonably Practicable (ALARP) the Company has employed a road transport consultant to study and implement the Land Transport Best Practice that could be sustained through the field life.

By implementing; a) road environment improvement, b) crude fleet improvement, c) public awareness campaign and engagement, and d) crude evacuation management, i.e. set up a defensive driving training center, journey management plan, driver reward programme the Potential Loss of Life (PLL) of 8% - 10% could be realized, compared to previous years PLL of 16% - 18%.