bluuebunny/crossref_metadata_2025 huggingface dataset:
Impact on Scale Management of the Engineered Depressurisation of Waterflooded Reservoirs: Risk Assessment Principles and Case Study
Authors: Chekani M. , Mackay E. J.
Published: December 2007

Increased oil and particularly gas production may be achieved in waterflooded reservoirs by stopping further water injection, and depressurising the reservoir to release solution gas.Pressure depletion may be accelerated by back producing injected brines.However, there is the possibility that these brines may cause formation damage by mobilising fines or deposition of inorganic scales.Scale deposition in production wells may also occur as a result of pressure depletion, with calcite scales being precipitated when the system drops below the CO2 bubble point pressure.This paper discusses the assessment and prediction of scale related formation damage problems that are likely to occur during depressurisation of a case study field.The potential for the specific problem arises from the formation of barium sulphate scale as a result of mixing of injected and formation brines during production.Data used in this study includes well brine chemistries and an existing finite difference reservoir simulation model of the field depressurisation, which was used to calculate the mixing of injected and formation brines, and the movement of the mixing and temperature fronts during waterflooding and subsequent depressurisation.

This study has determined that the behaviour of the scaling potential for each well in this field is different.Also, the degree of scaling, both deep within the reservoir where it does the least damage, and around the wellbore (for both injectors and producers) where it may adversely affect production, can be predicted by detailed modelling using both conventional and reaction-flow simulations.Former injectors converted to water production or infill wells drilled in the aquifer for pressure depletion may experience an increase in the scaling potential that significantly impacts the economics of the project because of the need for extensive prevention (inhibition) treatments.The increased scaling potential in these wells is a result of the dynamics of brine mixing in the reservoir, the lowering of reservoir temperature in the vicinity of injection wells during waterflooding, and the large volumes of water that require to be produced to achieve depressurisation.The magnitude of the scaling problem and the economic impact are lower for the production wells due to lower water production rates and higher temperatures.
Scale Control Within North Sea Chalk/Limestone Reservoirs. The Challenge of Understanding and Optimizing Chemical Placement Methods and Retention Mechanism: - Laboratory to Field
Authors: Jordan M. M. , Sjursaether K. , Collins I. R.
Published: December 2007

The scale control challenges for two North Sea carbonate reservoirs are reviewed in this paper. Whilst carbonate reservoir are not the largest source of hydrocarbon within the North Sea, they are very significant on a global bases.

The mechanism of scale inhibitor chemical retention observed for phosphonate, polymer, and vinyl sulphonate co-polymer inhibitors on carbonate reservoir substrates is outlined. Chemical placement represents the most significant technical challenge when performing scale squeeze treatments into fractured chalk reservoirs. Examples from over 50 field treatments applied in reservoirs E and V, where both phosphonate and vinyl sulphonate polymer chemicals have been deployed, are used to illustrate the difference in chemical retention observed in laboratory evaluations. The laboratory studies demonstrated clear potential for significant extension in treatment lifetime by changing from a phosphonate to a vinyl sulphonate co-polymer-based scale inhibitor. The selection and qualification of chemical placement systems for deployment of inhibitors in fractured carbonate reservoirs are also outlined. To this end, novel technologies to enhance conventional scale inhibitor chemical placement are vital to economic success during water flood projects.
Acid Fracturing With Encapsulated Citric Acid
Authors: Burgos Gerardo , Birch George , Buijse Marten
Published: December 2007

The paper evaluates the design considerations and execution results of the first commercial field trial of a novel acid fracturing technique, using encapsulated citric acid as the etching agent. The treatment was executed in the Maraca tight carbonate oil reservoir (16,000 ft, 270°F) under Lake Maracaibo, Venezuela. The main driver for this trial with an alternative acid was to obtain a significant increase in etched fracture length, over the current standard acid formulation for this reservoir of acetic and formic acid. The encapsulated citric acid is solid at temperatures up to 180°F and coated with vegetable oil to avoid dissolution in the carrier fluid. The job was designed for a target etched half-length in excess of 300 ft. The job was an operational success, placing 30,000 lbs of the solid acid in the formation. Post-treatment results, however, did not show any improvement in production from the test well. The paper also reviews several of the possibilities for the failure of the treatment and the limitations of the technology as an effective acid for fracturing carbonate formations.
Model for Displacement of Herschel-Bulkley Non-Newtonian Fluid by Newtonian Fluid in Porous Media and Its Application in Fracturing Fluid Cleanup
Authors: Yi X.
Published: December 2007

Recent laboratory and field studies performed by oil and gas service companies indicate that fracturing polymer may exhibit yield stress after water leak-off. Its rheology may be described by Herschel-Bulkley model. It is reported in the literature that yield stress might be responsible for low fracturing fluid cleanup efficiency. In this paper, we derive an extended analytical Buckley-Leverett type model for the displacement of non-Newtonian Herschel-Bukley fluid (e.g. fracturing fluid) by Newtonian fluid (e.g. hydrocarbon/water). Using this model, we study the effect of yield stress and other rheological parameters on fracturing fluid displacement efficiency. Parametric analysis indicates that high values of yield stress τ0, consistency index K’ and flow behavior index n’ lead to low displacement efficiency. It is found that, for a given set of relative permeabilities, if a pressure gradient is not enough to overcome a critical pressure gradient, non-Newtonian fracturing fluid will not flow and only Newtonian fluid will be produced. It is demonstrated that low displacement efficiency can be overcomed by increasing displacing rate.
Diversion and Cleanup Studies of Viscoelastic Surfactant-Based Self-Diverting Acid
Authors: Lungwitz Bernhard , Fredd Chris , Brady Mark , Miller Matthew , Ali Syed , Hughes Kelly
Published: December 2007

A self-diverting-acid based on viscoelastic surfactant (SDVA) has been used recently on stimulation treatments of carbonate formations. The new system has been proven successfull in more than 250 field applications.

The decrease of acid concentration during the spending process viscosifies the fluid by the transformation from spherical micelles to an entangled wormlike micellar structure while penetrating the carbonate rock. The highly viscous fluid acts as a temporary barrier and diverts the fluid into the remaining lower-permeability treating zones. After treatment, the SDVA barrier breaks when contacted either by formation hydrocarbons or pre-and post-flush fluids. Quantifying diversion, fluid efficiency, and cleanup are important factors for successful candidate selection and job design. Laboratory tests defining these key factors are presented in this paper.

This paper demonstrates the diverting ability of the acid as a function of permeability, characterized by introducing the concept of maximum pressure ratio (dPmax/dPo) supported by core-flow and acid conductivity tests using limestone and dolomite cores. Results demonstrate high dPmax/dPo in high-permeability cores and low dPmax/dPo in low-permeability cores. Retained permeability measurements are presented that assesses the level of cleanup. Flow initiation experiments of spent acid systems with gas and brine were performed to illustrate the cleanup behavior of SDVA in comparison to gelled acid systems under conditions encountered in gas and oil wells. The results indicate that SDVA systems clean up easily and that SDVA provides higher regained permeability than conventional gelled acid systems.
Optimizing Drill-In Fluid & Completion Cleanup Processes for Openhole Horizontal Gravelpacked Completions in Low Temperature Environments
Authors: Davis E. , Hodge R. , Dick M. , Mason S. , Martens H.
Published: December 2007

Drilling and completing extended length horizontal wellbores through low-temperature (<80°F) unconsolidated, high permeability reservoirs presents significant technical challenges and operating complications that can significantly impact initial well performance. Integrating the design and functional attributes of reservoir drill-in fluids with the various completion fluids, and their application processes, can produce significant benefits with respect to well performance.

This paper presents and discusses the technical challenges and issues confronting the design and implementation team responsible for installing the first horizontal openhole gravelpacked completion on the North Slope of Alaska. The gravelpacked horizontal well, 2T-218 was installed in the Greater Kuparuk Area's Tabasco field. The paper presents a case history detailing the fluids integration process and validation efforts utilized to develop and implement the reservoir drill-in fluid and filtercake cleanup treatments applied to the gravelpacked completion. The paper discusses the specific design criteria for the various fluids used in the drilling and completion operation, the design and laboratory testing process to determine the optimum recipes, the results of these lab tests, a summary of each field operation, and provides a synopsis of well performance obtained.

The unique conditions of application for this well in the Tabasco field in Alaska include: Medium to coarse pebbly unconsolidated sand and siltstonesHigh permeability contrast (1000 to 10,000 md)Low Bottomhole Static Temperature (76°F)Low Bottomhole Pressure 6.7-lbm/gal equivalent.

The principle issues with which the team had to deal were: Management of the properties of reservoir drill-in fluids utilized at low circulating and bottomhole static temperatures.Effective hole cleaning properties required for the horizontal section.Drilling fluid losses to the 6.7-lbm/gal reservoir.Wellbore stability and stuck pipe through the unconsolidated sand.The potential for formation damage of the high permeability & low-pressure reservoir interval.Adequate lubricity in order to successfully drill the horizontal section.The ability to degrade the drill-in fluid filtercake from behind a sand exclusion liner and coarse (12/20) gravelpack.The risk of and the methods to mitigate potential corrosive damage to the 13-CR completion equipment in the event of prolonged exposure to the filtercake cleanup treatment fluid.The reaction rate, uniformity, and efficiency of filtercake cleanup treatments.The effect of lubricants with respect to filtercake cleanup treatments and retained permeabilityThe performance of enzymes utilized in low temperature cleanup treatments.
Application and Performance of Single-Trip, Multi-zone, High-Rate Water Packs in a Mature Low-Pressure, Low-Temperature Gas Field
Authors: Ledlow Lewis B. , Seitz Brian T.
Published: December 2007

A total of six high rate water packs were installed in two wells utilizing a single trip, multi-zone gravel pack technique. The multi-zone gravel pack tool system allowed the installation of multiple gravel packs with a single run into the wellbore.1, 2, 3 This gravel pack system was chosen to reduce rig time and to minimize fluid loss into the low pressure, high permeability gas sands. In this high permeability reservoir, frac packing did not appear necessary for stimulation. The multi-layered reservoir and low strength rock made it highly unlikely that single, planar fractures could be created that would grow and connect up all the individual sands. Emphasis was placed on completion efficiency to minimize the effects of non-Darcy flow that severely limit the productivity of conventionally completed wells.

This paper describes the nodal analysis and well test evaluation techniques used to assess the rate limiting effects and completion inefficiencies of existing completions in this field. Also presented are single-trip, multi-zone gravel pack completion design and installation techniques that provided two to five times the productivity over conventional completions in a mature, low pressure, low temperature gas field. Sustained deliverability from the two completed wells has deferred both rig and non-rig wellwork for several years.
Designing and Obtaining Optimally Productive High-Rate Gas Wells From Horizontal Openhole Gravelpacked Completions: The Hibiscus Experience
Authors: Folefac A. , Hylkema H. , Mason S. , Graham A. , Svoboda C. , Guzman J. , McCartney R. , Patey I.
Published: December 2007

This paper summarizes the systematic methodology & engineering process employed to identify and refine the highly effective fluid-train solutions used to drill, and install the highly productive, long horizontal gas well completions of the NCMA Hibiscus Project offshore Trinidad. It presents and discusses the unique fluids design, pre-project evaluation, and the integrated application efforts undertaken to: 1.) Minimize formation and completion damage; and 2.) Maximize gravel-pack placement and filtercake removal efficiencies. The paper will identify important reservoir drilling and completion fluid service integration points (metrics), laboratory validation methods employed, and provide completion process details that led to the successful high-rate gas well installations in an unconsolidated sandstone reservoir.

Specific topics discussed will include: the design and implementation of: the optimized Reservoir Drilling Fluid (RDF), RDF to Completion Fluid displacement, gravelpacking process, and the filtercake removal treatment. Finally, the paper will present case histories of the five completions installed in the Hibiscus reservoir and provide comparisons of: 1.) RDF drilling performance, 2.) gravelpacking efficiency, and 3.) well performance (productivity) of a stand-alone screen completion versus the gravel packed wellscreen completions that employed the unique RDF and filtercake cleanup treatments.
Laboratory and Economic Evaluation of the Impact of Chemical Incompatibilities in Comingled Fluids on the Efficiency of a Produced Water Reinjection System: A North Sea Example
Authors: Collins Ian R. , Graham Gordon M. , Stalker Robert
Published: December 2007

As regulatory limits for oil discharge become more stringent and environmental awareness increases, produced water re-injection has become increasingly attractive for operators. However, as offshore developments become more complex, with new fields producing through existing facilities, the PWRI design team must face the problems involved in combining and re-injecting potentially incompatible fluids and/or production chemicals.

The Cleeton facilities in the North Sea provide an example of such a PWRI system. These facilities are the hub for the Easington Catchment Area (ECA) and are due to process fluids from an increasing number of new developments in coming years. This paper describes how the results of an extensive laboratory-based formation damage test program (SPE 80257) were combined with near-wellbore injection simulations and economic modelling studies to enable the economics of the treatment program to be defined. This laboratory study demonstrated that one of the production chemicals present in the expected co-mingled fluids exhibited a significant incompatibility with the formation rock, leading to in situ precipitation near the injection face. This resulted in significant reductions in injectivity. Additional work demonstrated that a number of remedial treatments were available to restore injectivity. Near well-bore injection simulation studies were used to predict the rate of reduction of well injectivity and therefore the timing of requirements for remedial treatments at the injection well. This enabled the economics of the treatment programme to be defined. This in turn allowed the cost benefit of the "PWRI incompatible chemicals" during the production stage to be weighed against the cost of remediation treatments during the re-injection stage. The outcome of this work was to recommend that an alternative chemical strategy was adopted in order to reduce the total costs associated with the proposed PWRI system. Preliminary data from the field implementation of the PWRI scheme is also discussed.
Design, Implementation, Results, and Key Learnings: Case Study of a Novel Single Trip, Perforated, Multi-Zone, Isolated, Frac Pack Completion - Keong Subsea Development, South China Sea Floater Operations
Authors: Davis E. R. , Curran J. , Palthe P. , Saldungaray P.
Published: December 2007

The Keong subsea development is located in Indonesia's Natuna Sea section of the South China Sea in the Block B concession operated by ConocoPhillips on behalf of itself and its co-venturers ChevronTexaco and Inpex. This gas field is one in a series of ConocoPhillips' subsea developments currently underway to fulfill key Southeast Asian long-term gas supply contracts. Therefore, high performance completions are required to drive efficiency in capital-intensive floater operations and subsea environments.

Keong 1 was planned as a cased hole perforated, fracpacked, multi-zone producer. The well was designed to develop a series of laminated high gross to net unconsolidated sands in the temporarily abandoned discovery well, saving both time and money over a new drill. Four separate sand bodies were targeted in the completion. The type of completion was selected to match the existing wellbore configuration, reservoir properties and productivity needs. A sand exclusion completion was designed that would enable the development of the highly laminated reserves.

A single trip, fracpacking, sand exclusion liner completion system to minimize expensive floater rig time and to minimize reservoir/near wellbore damage from well killing operations was also required. A novel combination of multi-zone Alternate Path Technology (APT) isolation packers, with APT sand exclusion liners enabled the simultaneous fracpacking of the three individual zones in a single fracpacking operation. Details of the fracpack design, tool modifications, field application and field observations are discussed.

Acquired pressure data from downhole sensors demonstrates that effective fracpacking of all zones was achieved. Results from subsequent production and pressure build-up data prove the attainment of a zero to negative skin verifying the applicability of the tools and process. This application resulted in savings to ConocoPhillips in completion costs, in addition to the production acceleration benefits of an efficient completion.

The objective of this paper is to present a "conception to production" high performance sand exclusion completion case history from ConocoPhillips' Keong subsea development in the South China Sea. Throughout the paper the design, implementation, operational problems, well performance results and key learnings will be discussed in detail in order to advance the technology and document the proposed completion methodology as an alternative for high deliverability wells.
Efficient Alternative to Control Sand Production in Wells with Oil/Water Contact at the Wellbore
Authors: Brito-Rhor Luis , Kuyucu Osman , Flores Jose G.
Published: December 2007

Sand production has proved to be a severe and often costly problem in many wells in the Oriente basin of Ecuador. Sand production has a negative impact over the productivity and lifting cost when it accumulates as sand plugs in the tubing, the surface flowlines or the surface pipes or vessels, and also when eroding the stages of the electric submersible pumps, shortening their run lives. Traditional techniques used to control sand production, such as conventional screens or gravel packs have been tried by Alberta Energy Company (AEC) in Ecuador resulting in impaired productivities of up to 75%, and therefore, are considered inefficient. Other techniques are not effective because of the broad grain size distribution, and also because the production of AEC in Ecuador typically comes from moderately thin and clean reservoirs, with bottom aquifers in the well. AEC and the majority of operators in Ecuador have not yet been able to control sand production without substantially reducing the oil production.

This paper presents an efficient and economic alternative to control sand production. It consists of a filter that is run in front of the perforations and that once properly packed, can virtually stop the sand without affecting the production of fluids. The completion is simple and significantly less expensive than comparable techniques. The proposed methodology has been tested so far in six AEC producers in Ecuador at flow rates up to 3000 bfpd, controlling the sand without affecting the total flow rate or the flowing pressure. A significant part of the success is attributable to a new procedure, introduced here, to naturally pack the screen.

This work summarizes the experience of AEC Ecuador in techniques to effectively control the sand production and it is supported by an extensive amount of field data. The results obtained here have served to demonstrate that designs customized to fit specific reservoir conditions can help maximize the well's productivity and to optimize the completion costs.
Evaluation of the Relative Importance of Parameters Influencing Perforation Cleanup
Authors: Detwiler Russell L. , Morris Joseph P. , Karacan C. Ozgen , Halleck Phillip M. , Hardesty John
Published: December 2007

Completion of cased and cemented wells by shaped-charge perforation results in damage to the formation, which can significantly reduce well productivity. Typically, underbalanced conditions are imposed during perforation in an effort to remove damaged rock and shaped-charge debris from the perforation tunnel. Immediately after the shaped-charge jet penetrates the formation, there is a transient surge of fluid from the formation through the perforation and into the well bore. Experimental evidence suggests that it is this transient pressure surge that leads to the removal of damaged rock and charge debris leaving an open perforation tunnel.

We have developed a two-stage computational model to simulate the perforation process and subsequent pressure surge and debris removal. The first stage of the model couples a hydrocode with a model of stress-induced permeability evolution to calculate damage to the formation and the resulting permeability field. The second stage simulates the non-Darcy, transient fluid flow from the formation and removes damaged rock and charge debris from the perforation tunnel. We compare the model to a series of API RP19B section 4 flow tests and explore the influence of fluid viscosity and rock strength on the final perforation geometry and permeability.
Dynamic Under Balanced Perforating Eliminates Near Wellbore Acid Stimulation in Low-Pressure Weber Formation
Authors: Stutz H. Lloyd , Behrmann Larry A.
Published: December 2007

Completions in the Weber formation have historically been perforated over balanced and then acid stimulated. Flow rates before acidizing were virtually 0 Mcf/D. Acid was an important step in the completion process. The Weber gas reservoir has low permeability (0.5 - 1.5 mD) and is now low pressure (2800 to 2300 psi at 14,000 ft). Typical flowing rates for these wells range from 1 to 5 MMcf/D. A new perforating technique utilizing the dynamic under balanced method was implemented in two wells, Brady 38W and Brady 56W. The wells were perforated with tubing-conveyed guns with initial over balances of 3250 and 3750 psi. The dynamic under balanced method creates an instantaneous under balance even though the annular space between the gun and the casing is initially over balanced. This perforating method also leaves significantly less perforation "skin." The proof is in the success of the two wells, which have rates equal to or in excess of the existing wells and yet required no acid stimulation. From historical comparisons of 18 prior completions, these wells should have had nearly zero flow without acid when perforating using an initial over balance of up to 3750 psi in the annulus. This paper discusses the new dynamic under balanced perforating design and its application to low-permeability, under-pressured reservoirs.
Benchmarking the Formation Damage of Drilling Fluids
Authors: van der Zwaag C. H.
Published: December 2007

The "Unified test protocol for laboratory formation damage assessments" consists of functional procedures that attempt to standardise formation damage service projects. Setting functional requirements was preferred above detailed instructions with respect to laboratory work processes and the handling of laboratory equipment.

In order to assess the formation damage potential of a fluid for drilling or well operations, three sections of the protocol need to be accomplished. These are respectively: "Information", "Simulation" and "Analysis".

This paper presents the three sections of the unified protocol and discusses the effect of the functional approach. Special emphasis is put on a distinction between well fluids that experience dynamic and static filtration regimes, as these require different ways of simulating fluid applications to the rock sample. To provide engineering parameters relevant at field scale and to identify the full range of potential formation damage mechanisms that may affect the reservoir, analyses on "centimeter", "millimeter" and "micrometer" scale are suggested.

Minimum requirements to upscale formation damage measurements to field scale are presented. We also present an option for full scope "diagnostic" formation damage assessments.

Applications of numerical models that have been suggested in earlier research yield "return permeability", "filtrate invasion depth", "lab skin", "efficiency of flow" and "loss of revenue" as parameters to benchmark the formation damage of well fluids.
High-Permeability Fracturing: "Carter" Fluid Loss or Not
Authors: Smith Michael B. , Bose Michael , Klein Henry H. , Ozenne Brent R. , Vandersypen Ron S.
Published: December 2007

Frac-packs, and hydraulic fracturing, have become accepted, successful completion procedures for high permeability formations. To some extent, this success has come despite less than full understanding of the processes. Statements such as "fracture models cannot predict net pressure behavior in soft rocks" are heard. Inconsistencies are blamed on radical departures from "classical" theories of fracturing, and in some instances, this may be warranted. However, it is best to first examine simpler possibilities (Occam's Razor). Radical departures should not be postulated until fracture models routinely address actual geologic/reservoir environments.

What is the big difference for high permeability fracturing? Of course, it is not "soft" rock, it is permeability, thus, fluid loss. ALL fracture designs are based on the idea of 1D, i.e., Carter or C/ t, loss, and assume (with no justification) this is valid. High loss is accounted for by high fluid loss coefficients, but using high values for something does not describe the process. One possible cause of the inconsistency might be non-1D, i.e., non-Carter type, loss behavior.

Non-1D fluid loss occurs in water injection/water disposal fractures (though "normal" fracture models are still mistakenly utilized in these situations). 1D loss is valid if the fracture propagation is greater than loss velocity, and this condition is NOT true for water flood induced fracturing. Is this true for high permeability fracturing - with fluid efficiency < 10%, even in propped fracturing treatments using viscous fluids?

This paper examines this question using a coupled 3D fracture-reservoir model (as described in Appendix A) to accurately simulate fluid loss. We simulate several field cases, review the design/post-analysis based on "traditional" loss behavior, and examine the effect of rigorously simulating loss. The results are used to identify conditions where non-Carter fluid loss is significant, and how to modify designs appropriately.
Development of a Novel Alcoholic Acid System for Removal Damage Resulting from Hydraulic Fracturing in the Tight Gas Reservoir
Authors: Wang Xugang , Zou Honglan , Chen Yandong , Zhang Fuxiang , Peng Jianxin
Published: December 2007

This paper presents a novel alcoholic acid system to remove the damage caused by frac fluid in tight gas reservoir. Damage resulting from hydraulic fractures takes two distinct forms: damage inside the fracture itself because of inadequate breaking of the fracturing fluid polymer; and fracture-face damage because of excessive leak-off. The objectives of laboratory experiments are to identify potential damage and aid selection of the optimum treatment fluid and design. A novel alcoholic acid flow tests illustrated the permeability increased because of pore & throat enlarged by using mercury intrusion experiments. It was critical in addressing issues of selection of fracturing fluids, polymer concentrations and breakers. Improved breaker systems show even greater benefit when used in conjunction with the lower loading polymer systems. The newer fluid systems enhance load recovery and reduce formation exposure to potentially damaging polymer residue.

DB gas reservoir is a low porosity, low permeability reservoir in the northwest of China. Large scale of hydraulic Fracturing has been carried out as effective method to get high gas production rates. However, the gas production rate after treatment increased to 335,683m3/d, and then declined to 34,875m3/d rapidly. The skin factor from well testing after hydraulic fracturing was 112, which indicated fractures and formation may appear damaged seriously because of more than 60% of the load fluid can be invaded and trapped in the formation by entering the smaller capillary pores during higher injection pressures. The gas production rate recovered from 32,383m3/d to 301,374m3/d and kept constantly by using treatment method of a novel alcoholic acid system.
Stabilizing Wellbores in Unconsolidated, Clay-Laden Formations
Authors: Nguyen Philip D. , Dusterhoft Ron G. , Ali Syed A. , Lockman Russell R.
Published: December 2007

This paper presents results of laboratory and field testing performed to investigate the feasibility and effectiveness of applying a one-component, low-viscosity consolidation material to stabilize or strengthen the unconsolidated formation sand surrounding a wellbore and overcome the effects of cyclic loading, while minimizing any reduction of its original permeability. Treatment fluid volumes, overflush fluid, and the chemical composition of the consolidation material were found to directly impact the consolidation performance and the retained permeability of the treated formation sand. The treatment renders formation fines immobile so that migration and plugging do not occur.

This study has determined that application of a consolidation material containing a specific solvent chemistry for clay-laden sands has resulted in excellent strengths even at high clay contents. This new finding indicates that the new approach allows the consolidation material to be drawn onto the mineral surfaces, resulting in very minimal loss in effective porosity. Scanning electron micrographs of the consolidated core material clearly reveal the entrapment of fines as the consolidation material formed a thin film on the mineral surfaces, resulting in very little damage to the porosity and permeability of the formation.

Results of field testing indicate that the consolidation treatment effectively stops the production of formation sand and fines while maintaining the production of the wells at desirable flow rates. The technique provides a very attractive alternative to conventional sand control completions in lower quality reservoirs as well as an effective thru-tubing completion alternative.
Responsible Exploration In A Tropical Forest
Authors: Ratanga R. , Lee M. , Louis A. , Smit C. H.
Published: December 2007

The protection and conservation of the Earth's nature and biodiversity is one of the greatest challenges of our time. Areas of overwhelming richness and fragile environment are located in Gabon with Shell Gabon's major activities carried out in a protected area in the heart of the rain-forest. Protective environmental measures are considered of eminent importance. These are critical to meet Shell's objective of responsible exploration combined with the conservation of an unique ecology. In this context several initiatives are actively pursued: (i) dedicated emissions reducing projects are either implemented or nearing realisation (2) re-vegetation programmes are executed to minimise the impact of deforestation and (3) a Biodiversity project was started to document biological diversity in areas in and out of oil operations.
Strategic Assessment of Oil and Gas Activities: Looking Beyond EIA/SIA
Authors: Wagner Jay Paul , Jones Murray G.
Published: December 2007

Throughout the world energy companies face a complex agenda requiring improved social and environmental performance. Alongside health, safety and environmental (HSE) issues, questions relating to human rights, revenue sharing, biodiversity, ethics, governance, corruption and the social and economic implications of energy activities are rising to the fore. This requires an understanding of the wider social, economic and political context of energy activities. Indeed, social, economic and political factors can play a crucial role in determining whether and at what pace development proceeds; something that traditional ESIA does not always capture given its focus on project-specific issues. The objective of the paper is to outline the purpose and value of high level, strategic impact assessments of the social, cultural, political, economic and environmental impacts of energy projects. The focus is on providing examples of the practical application of these assessment techniques rather than to dwell on theoretical models and to compare them to other forms of "strategic" assessment.
HSE And SD Assessments - Integrating HSE and Sustainable Development into Projects Right from the Outset
Authors: Cassin John
Published: December 2007

HSE and Sustainable Development (SD) issues and opportunities need to be identified and assessed at the earliest possible stages in projects in order to effectively manage the risks and optimize the opportunities. This paper describes a journey of improvement from a loosely structured distributed process to a more structured cross-functional process supported by simple user-friendly tools.
Safety Assessment of Alarm Systems on Offshore Oil and Gas Production Installations in Norway
Authors: Bjerkebaek Eirik , Eskedal Trond Sigurd
Published: December 2007

High quality alarm systems are essential to safe offshore petroleum production. The Norwegian Petroleum Directorate (NPD) has carried out safety assessments of alarm systems on seven of the petroleum production installations in Norway. The assessment clearly demonstrates that poor alarm system performance and management represents the greatest human factor challenge within control room environments offshore.
CO2 Capture Project: Initial Results
Authors: Wright Iain W. , Lee Arthur , Middleton Peter , Lowe Cliff , Imbus Scott W. , Miracca Ivano
Published: December 2007

CO2 capture and geological storage could provide a significant GreenHouse Gas (GHG) mitigation option if the cost of capture can be reduced and the public can be assurethat geological storage is safe, measureable and verifiable.

The CO2 Capture Project (CCP) is a public/private partnership initiated in 2000 to address the two issues above. Industry participants are BP, ChevronTexaco, EnCana, Eni, Norsk Hydro, Shell, Statoil and Suncor. Government funding was provided by USA, EU and Norway. Project funding was $50mm over three years (including cash and in-kind contributions). CCP objectives were to:

Develop low cost next generation technology, which achieves the ability to capture and geologically sequester from industrial turbines, boilers, heaters, and power generation systems, which emit CO2. Determine the key principles and practices to maximize the volume of CO2, which can be safely sequestered in geologic formations. Develop procedures and guidelines to monitor and verify storage of CO2 in geologic formations. Identify and recommend policies and incentives, which may enhance economic viability of CO2 capture and sequestration schemes.
Successfully Integrating the Challenge of Global Climate Change with Business Strategy
Authors: Sadorra Ronnie J.
Published: December 2007

Shell Canada Limited (SCL) shares the concern being expressed globally over the issue of climate change. We accept that there is sufficient evidence of a human impact on the climate system to support taking action on climate change. Shell People will continue to participate with governments and other sectors of society, in the policy debate to develop and implement responsible actions that contribute to emissions reductions and also protect Canada's interests.

Climate change is a long-term issue. The economic and related lifestyle costs of emissions mitigation policies can be reduced if they are phased in over time. Shell Canada believes that a measured approach provides time for better scientific understanding of the climate system, for the development of new and turnover of old technologies, and for the development of less carbon-intensive fuels while allowing the economy and society time to adjust.

Our business strategy includes a vision for the future and actions to manage our role on climate change today. Thus, Shell Canada is committed to taking action on climate change and will strive to continuously improve the energy efficiency performance of existing and new businesses to reduce overall greenhouse gas (GHG) emissions.
Social Performance
Authors: Macklin Stephen , de Koning Saskia
Published: December 2007

For the purposes of this paper the definition of social performance is all the different ways - directly or indirectly - that EP businesses contribute positively to or impact negatively on the people in the communities and societies where we operate. Social performance should not be seen as a substitute for sustainable development, rather, as a key part of it.

There is no doubt - the old boundaries separating business and society have changed. Increasingly, society expects that businesses should make a contribution to it, and we want to make that contribution. It's the right thing to do. It allows us, individually and collectively, to realise our personal aspirations to make a positive difference in the world. Also, it enables our businesses to perform better.

Different groups of society have different expectations of us as Figure 1 shows. To act effectively, we need to recognise how we fit into society. In the past, EP companies’ view of the world was like that of most businesses, with themselves firmly at the center. Other organizations populated that world in an orderly, segregated way. Today the picture is more complex. EP companies interact with a wide range of other groups, in society, who also interact and overlap with each other. Traditional relationships no longer apply. Engagement and dialogue are crucial to managing our impact on others, and their impact on us, effectively - both now and in the future.

There is no time for delay. We should improve our social performance continuously by listening and taking appropriate actions. In addition, we should anticipate the future. We must get our projects and operations in shape for what will be required in 5-10 years time.

Shell EP's vision for social performance is to work in partnership to deliver net benefit to our neighbors, communities, and to wider society affected by our operations. This vision recognises that every project has its associated costs and benefits - some financial, some environmental, some social - for our businesses and for those affected by our operations. Although the ultimate balance sheet on impact should present net benefit to all, no group should pay too high a price.

The paper will outline social impact, and describe the recent developments within and key challenges faced by Shell EP, and the key features of its approach.
Delivering Employment Diversity on an Offshore Oil Project
Authors: Shrimpton Mark , Allan Margaret
Published: December 2007

There is a growing need to ensure that local areas receive a share of the jobs and business associated with upstream petroleum industry activity. In the case of Husky Energy's White Rose oilfield project in Newfoundland and Labrador, Canada, there is a government requirement to provide employment and business opportunities not only to residents of Newfoundland and Labrador, and other Canadians, but also to women, aboriginal peoples, visible minorities and persons with disabilities.

This paper describes how this requirement is being addressed by the White Rose Project Diversity Plan. The plan uses a non-prescriptive approach, allowing Husky and its main contractors to develop targets and initiatives that are appropriate to their organizations and activities, and to labour market constraints. It employs an iterative process whereby they establish annual diversity targets and monitor success in meeting them, leading to the establishment of new targets. The plan also seeks to foster a ‘diversity culture’ within project companies, and it emphasizes collaboration between Husky, its contractors and community groups, so as to access different networks and share expertise and lessons. These approaches may have application to employment and business diversity requirements on other projects worldwide.
Stakeholder Consultation and Environmental Implications for the Offshore Petroleum Industry: An Australian Perspective
Authors: Tantala Steve
Published: December 2007

The paper broadly outlines the importance of consultation as a vehicle to assist both industry and regulators. It then examines some practical applications of the consultation process. The paper commences with a brief overview of the petroleum industry in Australia.
Seeing the Wood for the Trees
Authors: Bridle Peter , Bonsall David
Published: December 2007

This paper describes the innovative approach taken by ENSCO International Inc. (a leading international offshore drilling contractor), supported by Risktec Solutions (an international safety and risk management consultancy), to consolidate a wide variety of worksite safety controls (e.g. Work instructions, Risk Assessments, Job Safety Analysis, Competence, Work Permits etc) into a single integrated system - the Safe System of Work (SSoW).

The program used existing foundations of Work Instruction and Job Hazard Analysis systems to move forward to a structured system that clarifies the differences between information to define the quality of the work and that relating to the management of the hazards associated with the work activity. The program provided further clarity over the management of hazards relating to the TYPE of work being performed, hazards relating to the LOCATION work was being performed and hazards relating to the TIME (i.e. conflicts with other work) when work is being conducted.

ENSCO International Inc. has been working with the SSoW for approximately 18 months in the Gulf of Mexico and, given the very positive feedback from the workforce, has established the SSoW as a minimum worldwide company standard. Expectations, purpose and relevancy of all worksite safety controls - both individually and collectively - are now clear, leading to a marked improvement in the communication of expectations at the worksite.

The SSoW provides an effective platform for communicating a wide range of requirements from such sources as HSE Cases, Environmental Management Systems (EMS), Preventative Maintenance routines, etc. through a ‘one stop shop’ for the workforce.
Safety in Decommissioning and Remediation of Remote Sites
Authors: Taylor Timothy R.
Published: December 2007

Every year oil and gas fields play out their useful economic life. Once production ceases, the facilities are often suspended awaiting their ultimate fate. In this time lag, until the sites are decommissioned and remediated, much will deteriorate. Also, during this period, infrastructure in remote regions often departs south, leaving the environmental project with a wide range of challenges that are not encountered in less remote areas.

Any decommissioning project can have many safety hazards. In a remote project, these hazards are magnified because of the difficulty in getting resources or emergency aid.

For example, the discovery of asbestos can endanger unprepared workers; it can delay the project while qualified contractors are retained and it will increase costs.

For a remote site, the solution is to plan, plan and plan for both the expected and a contingency plan for the unexpected. The first step in planning the project is to complete a hazard assessment.
Reaching Agreement Between Oil Explorers and Rock Lobster Fishermen Offshore Dongara, Western Australia
Authors: Cobby G. L.
Published: December 2007

During 2001-2002 new exploration permits were released offshore Western Australia for competitive bidding. These permit areas overlie a well established rock lobster fishery contributing around A$ 300 - 400 million per annum to the economy. A new oil field (Cliff head) was discovered within these rock lobster fishing grounds renewing interest in the area. Increased levels of petroleum activity have the potential to interfere with rock lobster fishing. The challenge for oil explorers and developers is to demonstrate to the rock lobster fishing community that exploration and production activity can be conducted without disrupting fishing activities. The paper describes the rock lobster fishery, the petroleum exploration activity, the consultation requirements and how dialogue between, rock lobster fisherman, oil explorers and regulators provide the basis for managing conflicting interests.