bluuebunny/crossref_metadata_2025 huggingface dataset:
In-Situ Heavy-Oil Fluid Density and Viscosity Determination Using Wireline Formation Testers in Carbonates Drilled With Water-Based Mud
Authors: Akkurt Ridvan , Seifert Douglas , Neumann Peter , Zeybek Murat , Ayyad Hazim
Published: February 2011

In-situ heavy oil density and viscosity can vary laterally and vertically in carbonate reservoirs. The spatial distribution of these PVT properties must be determined accurately for reserve assessment, reservoir simulation, well placement and other field development processes.

Although laboratory PVT analysis is the industry-standard source for fluid properties, the extensive time required to restore and process heavy oil fluid samples often minimizes the impact of such information during the drilling phase. The use of wireline formation testers, capable of measuring in-situ density and viscosity, can greatly aid the decision-making process providing timely basic PVT data, in addition to guiding the fluid sampling program and increasing the quality of the samples to be taken.

While in-situ measurement of fluid density and viscosity in oil-based-mud is well-established, accurate determination of such properties can be quite challenging in water-based-mud environments; especially in those cases of water-dominated flow, strongly emulsified fluids or high fraction of sediments in the flow line. Several techniques, such as sampling point optimization, pressure and flow rate control during pump-out, and tool-string configuration can minimize the adverse effects, thereby improving measurement and sampling quality. Yet, there can still be cases where the measurement accuracy can be limited due to the specific combination of fluid and formation properties, and borehole conditions.

In this paper, several case histories in a variety of borehole and mud conditions, including highly deviated and ultra-reach extended horizontal wells, are presented with comparisons to laboratory data when available. Results indicate that accurate in-situ density and viscosity determination is possible when sufficient amount of oil is present in the flow line. Experience also shows that measurement quality can be affected in suboptimal conditions involving strong emulsions, or range of viscosities outside the sensor specifications.
Development of Marcellus Shale in Pennsylvania
Authors: Belvalkar R. , Oyewole S.
Published: February 2011

A review of technologies and practices used for exploration and production of natural gas from the Marcellus Shale in Pennsylvania is given while shedding light on the entire process of natural gas production in the Marcellus Shale region of Pennsylvania. Entailing drilling and completions operations, production operations and transportation of natural gas tied together with regulation and policy in Pennsylvania. Horizontal drilling technology is used in shale play development along with well stimulation which is also needed to produce economically from these wells. This is achieved through hydraulic fracturing. Water is predominantly used for this but the use of other fluids is also being explored. For the transport of natural gas a network is present in Pennsylvania but gathering stations and other infrastructure needs to be setup. This is not easy in Pennsylvania due to the hilly nature of the region. Most common practices are developed locally as is the case in the Marcellus, with local operators and not the big majors heading the development of the Shale play but even they used techniques applied in the Barnett Shale to great success in the Marcellus Shale which goes to prove that a lot can be gained from other similar plays. The history of this region in producing natural gas is more than a hundred years old and so a lot has done in this region with regards to experimentation and technology additions in producing natural gas. Apart from producing and transportation of natural gas, another important aspect is regulation and policy which is strict when it comes to Pennsylvania. Along with this it would be beneficial for companies to develop good relations with residents in the area as these wells typically produce for long periods of time. Typical land restoration projects are now mandatory which all adds upto a higher overall cost of energy. To summarize all the factors needed to produce natural gas in this region economically and safely with leaving as small as a footprint as possible is explored.
Effectiveness of Water Jet Fracturing on a Horizontal Open Hole Completion: Case Study
Authors: Rosales Sigifredo J. , Hernández Rafael A. , Lynch Cynthia Yuen , Bustamante Ernesto
Published: February 2011

To date, the art of effective openhole, horizontal well fracturing is not well defined. Difficulties in regional sealing hamper the fracturing task and results can be suspect. Without proper isolation methods, the use of openhole, horizontal well fracturing is limited. During many fracturing processes, fracture or acid placement often occurs where fluid first contacts the borehole, often at the heel of the well.

A new method is now available that combines hydra-jetting and fracturing techniques. By using this new method, operators can position a jetting tool at the exact point where the fracture is required, without using sealing elements. Unlike other techniques, this new method allows operators to place multiple fractures in the same well; these fractures can be spaced evenly or unevenly as prescribed by the fracture-design program. Large-sized fractures can be placed with this method as well.

This technique was applied in a low-permeability environment in a horizontal, openhole completion. Treatment design proved simple, but unique to the job, to which success is attributed. In addition to tailoring a design for such treatment, reservoirmonitoring methods were applied to help measure the effectiveness of the overall stimulation program. Surface tiltmeter technology was used to map the hydraulic fractures. Mapping results indicated that induced fractures were placed in the area of interest, a well-documented difficult task on an openhole completion.

This paper discusses the basic principles of horizontal hydrajet fracturing on an openhole completion, observes the operational advantages of the technique, and highlights the significance of matching the right application to the right environment for treatment success.
Reservoir Modeling of CO2 Plume Behavior Calibrated Against Monitoring Data From Sleipner, Norway
Authors: Singh Varunendra , Cavanagh Andrew , Hansen Hilde , Nazarian Bamshad , Iding Martin , Ringrose Philip
Published: February 2011

Sleipner is a commercial CO2 storage site in the North Sea with good constraints from monitoring data, but also with some significant uncertainties regarding temperature, pressure and gas/brine behavior. At Sleipner, we have used high-quality repeated seismic and gravimetric surveys for monitoring and calibrating the reservoir uncertainties. To model the CO2 behavior we have used two main approaches: a) traditional reservoir simulations, using black oil and compositional fluid descriptions; and b) invasion percolation simulations, using threshold pressure and fluid density descriptions that assume the dominance of capillary and gravity forces. The key findings from the study are:

The invasion percolation simulation gave the best initial match to observed data, leading us to reassess the input assumptions for the black oil and compositional simulations. By taking into account gravity segregation and modifying the reservoir simulation input data, we were able to get a much better match for the black oil and compositional simulations. There is still scope for further optimization and history matching, however, this study has reduced the range of domain variables leading to an improved understanding of the flow processes involved in geological storage of CO2 in saline formations.

The study has led us to conclude that we can make realistic and predictive CO2 storage models provided that the site-specific conditions are honored, including reservoir and fluid property characterization. The necessary tight constraints on input parameters are achieved by calibration against monitoring data.

Our study illustrates both a rather novel approach to modeling CO2 storage and the need for improved input to conventional simulators. Application of our approach to other CO2 storage sites will help in achieving more realistic understanding of CO2 storage, thereby contributing to the maturation of CO2 storage technology worldwide.
Development and Usage of an Etched Transparent Flowcell for Visualisation of Biofilm Induced Heterogeneities in Porous Media using Particle Image Velocimetry
Authors: van der Kraan Geert M. , Buijzen Floris , de Ridder Maarten , Thuss Barbara , Laros Mario , Poelma Christian , Lomans Bart P. , Muyzer Gerard , van Loosdrecht Mark C. , Bruining Johannes
Published: February 2011

Flow cells (or ‘transparent micromodels’) are widely used to observe complex processes in two dimensional (2D) porous media. The objective of this study is to design, develop, and apply a wet-etched glass micromodel suitable for the observation of biofilm formation, transport of microorganisms and flow measurements using Particle Image Velocimetry (PIV). PIV in this case can be used for the visualisation and quantification of flow diversion. The wet-etching technique applied here is relatively straightforward. The paper addresses all aspects involved necessary to perform these experiments. The chosen etching depth of around 25 μm proved to be well suited for transport experiments with microorganisms. We show that the micromodel containing a wet-etched cell (wafer) provides a high quality image of transport and growth of microorganisms in porous media. The microorganism Pseudomonas chlororaphis was used as a model strain to perform the experiments on biofilm formation and transport. In the transparent cell, we could clearly observe biofilm formation. Moreover, we showed that PIV techniques can indeed visualize the change in flow pattern caused by biofilm presence.
Flexible Simulation of Faults
Authors: Røe P. , Abrahamsen P. , Georgsen F. , Syversveen A. R. , Lia O.
Published: February 2011

Fault geometry is modelled on basis of seismic data, but restricted by fault observations in wells. Due to uncertainties in depth migration, seismic interpretation and well data, there is a significant uncertainty in the geometry and position of the faults. Fault uncertainty impact reservoir volume, flow properties and well planning, and can be studied by stochastic simulation of faults.

We have developed a method for stochastic simulation of fault surfaces and fault networks using standard geostatistical methods. This is made possible by the fault parameterization used, where the faults are modelled as tilted surfaces. This new method is more flexible and efficient compared to already existing algorithms due to a simpler parameterization. Conditioning to fault observations in wells is also made simpler.

The fault is defined as a two-dimensional surface on a tilted reference plane. The uncertainty for a fault surface is bounded by a volume enclosing the fault surface. The smoothness of the simulated fault surfaces is controlled by variograms. The simulation is done by adding a simulated Gaussian residual. Well conditioning is done by kriging.

Using the described method we can simulate a set of fault realizations where the simulated faults look realistic, are within the defined uncertainty volumes, and honour well observations.

Technical contributions compared to previous work include efficient simulation of fault geometry, a flexible uncertainty model and well conditioning with no performance impact.
Improved Reservoir Characterization Integrating Seismic Inversion, Rock Physics Model, and Petroelastic Log Facies Classification: A Real Case Application
Authors: Roncarolo F. , Grana D.
Published: February 2011

A real case application of a seismic reservoir characterization methodology in a deep water clastic reservoir located offshore West Africa is hereby presented.

The aim of this study is to integrate seismic facies classification into the reservoir static modelling workflow. The proposed probabilistic approach for petroelastic properties estimation and facies identification based on seismic data can be divided into three main steps. First, a Bayesian elastic inversion is performed to obtain seismic impedances from partial-stack seismic data. Then, a statistical rock physics model is applied to estimate the posterior probabilities of porosity, clay content and water saturation from impedances distributions. Finally, a litho-fluid classification is performed combining petrophysical properties probabilities with log facies analysis at well location, to propagate the identified classes in the 3D grid. The final result is a set of probability volumes for each seismic litho-fluid facies that can be used as prior 3D trend for geostatistical simulations. Using Sequential Indicator Simulation algorithm several facies realizations are generated and relevant sets of petrophysical properties are simulated within each facies.

The developed workflow has been applied in a real case study offshore West Africa. The available reservoir model has been updated including the results of the petroelastic inversion, in addition to a set of seismically derived geobodies representing the main geological features (channels, levees and sand lobes). Integrated use of seismic 3D probability trends and geological constraints provides advantages in terms of a more detailed spatial distribution of rock properties, a meaningful geological 3D representation and a better understanding of vertical and lateral connectivity within the reservoir. Moreover, development wells may be optimized in a more reliable way.

The contribution of the presented methodology is of key importance for fields in early development phase with few exploration well data available to constrain 3D models.
A Unified Wellbore Model for Reservoir Simulation
Authors: Holmes J. A. , Byer T. , Edwards D. A. , Stone T. W. , Pallister I. , Shaw G. , Walsh D.
Published: February 2011

A comprehensive well model that exists within a next-generation parallel reservoir simulator is described. It incorporates a general formulation approach which handles global phase-component partitioning allowing any number of phases and components, where any component can exist in any phase. The model can run in either isothermal or thermal mode, the latter including special features for steam injection and production. A multisegment capability enables the wellbore to be divided into segments for improved accuracy when simulating horizontal and multilateral wells. This unified well model reduces to a ‘conventional’ model when a single segment is used.
Coiled Tubing: A Key Enabler for Successful Multifractured, Horizontal Wells in Recent Low-Permeability Gas Developments Offshore UK
Authors: Holland B. , Cruickshank B. , Coghlan G.
Published: February 2011

Stimulation technology advances and gas market fundamentals are giving a strong impetus to low permeability gas developments in the UKCS. Technologies developed in regions outside the UK were selected and tailored to this challenging, high cost, offshore environment.

The multi-fractured, horizontal well has been key to near-exponential growth in developments of various shale plays onshore; it was also key to an earlier unlocking of chalk plays offshore Denmark and Norway. Location and well construction practises mean offshore execution of this completion strategy is complex and expensive. Historic attempts offshore in Rotliegendes sandstone (the predominant play) fell prey to technical difficulties. As a result execution risk was perceived as high, operators did not consider it viable offshore.

The strategy was adopted and successfully executed in two fields operated by Centrica Energy*. Encouraged by its success other UK operators are executing offshore developments using the same strategy and it is being reevaluated by Dutch operators.

A key component and unsung ‘hero’ is coiled tubing and its use in the Chiswick and Ensign fields. This paper is a case study of the three wells drilled, completed and stimulated in 2007/2008. Such was the confidence in employing this technique; further wells were added in Q4/2009 and Q2/2010.

The paper discusses equipment used, problems experienced and working practices that evolved. For example, 2− 3/8" coiled tubing was deployed in one well with a 20,000 ft well TD at 11,000 ft TVDSS. In a five-stage stimulation program, coil was worked on multiple occasions to perforate and to clean a path through proppant in the liner. It was operated at the edge of its design envelope and operating parameters were revised and fine-tuned onsite. It proved capable of everything asked of it and is a key enabler to allowing these reservoirs to be developed.
Post-Plateau Reservoir Management in the Magnus Field
Authors: Moulds Tim P. , Trussell Phillip , Erbas Demet , Cox David J. , Laws Ewan D. , Davies Chris , Strachan Neil
Published: February 2011

Magnus is a high productivity oil field in the northern North Sea. First oil was produced in 1983 and the plateau of 150 MSTB/D ended in 1995. In the post-plateau period a variety of reservoir management techniques have been employed to arrest decline rate. Two major projects have been executed post-plateau: in 2002 a gas injection EOR scheme was initiated and more recently additional drilling slots were added to the platform to increase reservoir access. These major projects have rejuvenated the field development options and will enable significant oil production beyond the next decade.

The EOR scheme exemplifies the synergies that are important to continuing to extract value in a mature oil province. The gas that is injected is sourced from several other fields and provides an export route for associated gas that would otherwise be stranded. After seven years of operation the impact of the EOR scheme is readily quantified, as are the challenges inherent in operating such a scheme. This paper describes the reservoir performance of EOR, discusses observations that may impact gas relative permeability under WAG operation, describes the tools that have supported reservoir management decisions and considers the operational issues that continually challenge delivery and the surveillance approach taken to mitigate these.

The extended slots project used slot-splitter technology to increase the number of wells. Wells from the new slots are now the longest wells that have been drilled from the platform enabling recovery from targets at the periphery of the field.

The combination of EOR and additional slots has generated a position where the field is once again opportunity-rich. Together with technology developments in 4D seismic and revised geological description a new tranche of opportunities are being identified that combine initially dry oil attic targets along with the underpinning volumes from EOR delivery.
Estimation of the Potential of an Oil-Viscosity-Reducing Bacterium Petrotoga sp. Isolated from an Oil Field for MEOR
Authors: Purwasena Isty A. , Sugai Yuichi , Sasaki Kyuro
Published: February 2011

An anaerobic oil-degrading thermophile, Petrotoga sp. AR80, was isolated from reservoir brine of an oilfield in Japan. This bacterium degrades long-chain hydrocarbons of crude oil into shorter-chain hydrocarbons in brine medium. Therefore, the oil viscosity can be decreased and the enhancement of oil recovery can be expected by this bacterium. The potential of this bacterium as a candidate for MEOR was estimated in this study. Some nitrogen source which is essential for bacteria should be injected into reservoir to stimulate the bacterial growth. To select a suitable brine medium for this bacterial activity on the reduction of crude oil viscosity, the numbers of nitrogen sources were evaluated. The highest growth rate was observed in medium contained yeast extract with maximum cell concentration in this medium was 10 times higher than that in other mediums. The influence of reservoir conditions such as temperature, salinity, and pressure on the bacterium was evaluated. This bacterium can grow and decrease oil viscosity at a temperature between 50 °C and 70 °C. The oil viscosity incubated with Petrotoga sp. AR80 was 46.3 %, 51.6 % and 65.9 % lower than control after 3 weeks incubation at 50 °C, 60 °C and 70 °C. In addition, the oil viscosity was 35.1 % lower than control at 70 °C and 800 psi. The result of GC chromatogram showed that this bacterium can convert and/or degrade various components of oil lead to depletion in heavier oil components and enrichment of light oil components respectively. Oil extracted from Oman, China and Canada can be utilized by this bacterium instead of Japanese oil. These results show that the isolated bacterium can be applied to a wide range of reservoirs for MEOR. In addition, this bacterium achieves economically feasible MEOR because it doesn't need costly nutrients such as molasses which has been used as a nutrient in MEOR.
Identifying the Optimum Wettability Conditions for the Near-Wellbore Region in Gas-Condensate Reservoirs
Authors: Zoghbi B. , Fahes M. M. , Nasrabadi H.
Published: February 2011

The problem of condensate blocking in low permeability gas-condensate reservoirs is greatly affected by the rock-fluid interactions and capillary trapping. Many publications suggest wettability alteration to gas-wetting as a permanent solution to the problem. In this work, we present a simulation study on the optimum wettability conditions for maximum gas-condensate well productivity enhancement. Most of the work in this area focuses on reversal of wetting conditions from liquid-wetting (contact angle of 0 degree) to gas-wetting (with contact angle around 150 degrees). On the experimental side, chemicals are tested in its ability to change wettability. On the simulation side, research shows that changing the wettability to gas-wetting in the near wellbore region results in better productivity than the original liquid-wetting state. Our work investigates various states of wettability ranging from liquid-wetting to gas-wetting and its effect on gas-condensate well productivity. We also study the effect of reservoir permeability, reservoir pressure and treatment radius on the well productivity enhancement by wettability alteration.
Solid Earth Modeling and Geometric Uncertainties
Authors: Mallet J.-L. , Tertois A.-L.
Published: February 2011

In computer geoscience, reservoir studies aim at estimating hydrocarbons in place to determine prospect viability and define development strategies. Assessing uncertainty on reservoir geometry is even more important than assessing uncertainty on rock properties because the property model depends on reservoir geometry. The authors propose a methodology for assessing geometric uncertainties on a unified solid earth model and show its application to a subsurface model.

A reference structural model is perturbed to reflect geometric uncertainty and several equiprobable realizations of the structural model are created. Instead of applying one global transformation as in most current methods, geometric uncertainties from different sources are assessed successively or jointly in each realization. The difficult problem of maintaining geological consistency while modifying structural models is addressed by using a structural model which is solid-based rather than surface-based: fault/fault and fault/horizon contacts are watertight by construction and constraints developed for this project ensure horizons do not intersect. The structural model is linked to the property model by a three-dimensional transformation, which enables perturbing the structural model independently from the property model instead of applying geometric transformations to the property model or having to recreate a property model for each geometric realization.
Iwafune-Oki Gas-Flood; the First Commercially Successful Gas-Based IOR in Japan
Authors: Yamada Tomomi
Published: February 2011

Iwafune-Oki is the only offshore oil and gas field currently operated in Japan. It was discovered in 1983 and has been producing from several oil- and gas-reservoirs since 1990. After 8 years of plateau production, the field's oil started to decline whereas the gas-zones’ recovery had been constrained by the regional gas demand. There was incentive to arrest the oil decline using the abundant gas.

In 2002, IOR potential was reviewed on Zone 2100m, the main oil reservoir, using an existing numerical model and WAG injection of associated gas was identified as prospective. Although its economics was evaluated as marginal, it was decided to proceed to definitive study and pilot injection test as better reality was anticipated by such mechanisms that the simplified black- oil model could not sufficiently simulate. They include components exchange, double displacement and gravity segregation between the injected and the resident phases. The pilot test, sourced by an unexploited gas reservoir, was conducted in parallel with the study, because significant loss in the project economics was expected if the implementation was delayed.

The pilot injection, started in December 2004 has shifted to regular operation since 2006 using also other high-pressure gas zones. Around 2% of incremental recovery has already been achieved and URF is enhanced by 7% on P50 basis. While no apparent production decline has been observed, GOR has significantly risen. Installation of gas compressor is ongoing, which enables WAG injection and will add roughly 4% of increment to URF.

This story illustrates the importance of correct understanding on the recovery process and the nature of IOR implementation. Right judgments on the project come from precise understanding on the expected displacement mechanism versus limitations of the simulation model at hand. Economic gain is maximized through balanced management between the project's implementation speed and associated risk.
Field Experience Leads to Effective Bypass of Formation Damage Caused by Asphaltenes Deposition and Improves Production from a Naturally Fractured Carbonate Oil Reservoir
Authors: Strippoli Pasquale Danilo , Tiani Alessandro , Mauri Luca , Appicciutoli Danilo , Maier Robert
Published: February 2011

The largest active onshore field in Western Europe produces crude from 20 long horizontal wells from a naturally fractured carbonate reservoir. The produced crude deposited asphaltenes in tubing, openhole sections, and slotted liners. Over time, the deposition became so severe that it involved the reservoir fractures, affected well productivity, and caused a premature field-production decline. Removing the formation damage, therefore, became a priority for appropriate field management.

The injection of asphaltene inhibitors at packer depth reduced asphaltene deposition in tubing but did not protect the long openhole or the natural fractures from plugging. Bullheading or coiled-tubing (CT) solvent treatments were frequently performed with limited benefits.

In 2009, an extensive asphaltene cleanout campaign was performed with more aggressive solvent treatments, covering almost 70% of producing wells. Continuous post-treatment-analysis improved the stimulation effectiveness and optimizing the dissolving fluids led to a production increase per treated well of 500 to 3,500 bbl crude per day. Unfortunately, the treatment techniques applied did not allow sustained production increase unless well interventions were frequent, up to bi-monthly.

To reduce the treatment frequency, an emulsified-acid treatment was performed. The innovative emulsion, where acid was emulsified in solvent, provided a delayed acid reaction and allowed live acid to penetrate deeper into the formation. This allowed the flow pattern to be changed in a way such that the asphaltene deposition was slowed down, and the high well production was sustained over a prolonged period.

This paper describes the history of the treatment methods, the extensive asphaltene-cleanout campaign performed, the post-job analysis, stimulation-treatment improvements based on field experience, and the final novel application of an emulsified-acid treatment that sustained a prolonged production gain of more than 10,000 BOPD and recovered initial well productivity.
Inflow-Control-Device Completion in a Scaling Environment: Findings and Experiences Obtained During Production Logging in the Heidrun Field
Authors: Gustavsen Øyvind , Selle Olav Martin , Fadnes Finn Hallstein , Svela Per Einar , Gudding Erlend , Stene Karin
Published: February 2011

There is an ongoing debate in the industry regarding the use of ICD (inflow control devices) in wells with scale potential. Several concepts for ICD in sand screen completions were evaluated for the Heidrun field, and the equipment chosen had a robust design of the housing, into which the flow goes before entering the basepipe through the nozzles.

Oil field scale is an increasing challenge on the Norwegian continental shelf. One reason for this is the wide use of seawater for reservoir pressure support. Seawater contains sulphate, and mixing of such with barium and strontium containing formation water forms the basis for precipitation of low soluble sulphate salts. In commingled producers mixing of incompatible waters from different reservoir zones can occur due to seawater being flooded through high permeable zones.

The most critical places for scale deposition are the screen section and the DHSV (downhole safety valve). Deposition in the screens hinders inflow to the well and reduces the well productivity.

Recently collected production log data from an ICD completed well with sulphate scale potential forms an important basis for the evaluation of this novel completion solution. The well is a horizontal oil producer completed with 5 1/2" ICD standalone sand screen in 8 1/2" open hole. There are three inflow zones divided by swell packers in blank sections to avoid annular communication. Scale deposits present in the well seem to precipitate around the ICD nozzles inside the tubing, as seen from both GR (gamma ray) and x-y caliper data. Scale deposited in the middle zone does not disappear during the course of multiple logging passes in the well, while the deposits in the upper zone are clearly reduced. This indicates different precipitation processes for the two zones.
Assessment of Asphaltene Deposition Risk in an EOR Intervention Through CO2 Injection
Authors: Correra S. , De Simoni M. , Bartosek M. , Colombani G. , Diatto P. , Maddinelli G. , Parasiliti V.
Published: February 2011

Enhanced Oil Recovery through CO2 injection allows to reach a twofold valuable objective, increasing the amount of crude oil extracted from an oil field while mitigating the contribution of emissions to global warming. Such an intervention is planned in an oil production field in Sicily (Italy) by employing a CO2 stream already available from an oil refinery located near to the field. The oil is currently produced through a pump artificial lift and fluidized by a fluidizing stream injected at the bottom of the well, due to its characteristics: it is an heavy, asphaltene-rich oil. Just these characteristics worried about the possibility that injected CO2 could destabilize the asphaltene fraction, leading to the formation a of a sludge or a solid phase, that would plug the formation pores and, ultimately, decrease injectivity and productivity. In order to assess this risk, the eni in-house-developed asphaltene deposition model was employed to investigate various conditions close to the expected operating conditions. At the same time, a lab activity was undertaken, in order to have an experimental check at least on a narrow range of conditions. Results of these activities showed that no deposition happens in the expected range of operating conditions.

A description of both simulation and experimental activities is reported, in order to show how it is possible to assess the risk of asphaltene deposition before operations potentially dangerous to the field productivity.
Achieving Sustainable Incident-Free Operations through Managing the Human Factor: A Success Story of Applying E-Colors
Authors: Barakat Eli R. , Barber Jonathan C. , Wood Jeff S.
Published: February 2011

Safety professionals have often linked safe or less-than-safe behaviours to human character, but never to personality.

If we examine behaviours in this context, we often see that reactions are dictated by personality, whereas it is character that determines response. Studies and surveys conducted on over 20,000 people (also presented in SPE paper 95346-PP) concluded that individuals with different personalities - the Socializer (Yellow), the Director (Red), the Thinker (Green) and the Relater (Blue) - recognize and react to hazards in various ways. These personality types are referred to as "E-Colors".

The cause of injuries differs with each of the personalities as risk mitigation, stop work authority, and how one can become injured, are recognized from different perspectives; for example, the Socializer, who optimistically focuses on people and the big picture, could become injured by jumping in to help others, or miss details associated with pre-planning or a task itself. In comparison, the Director who, typically, is results- and goal-oriented, can become injured through self-induced time pressure, or allowing calculated risks to be taken in order to complete the task.

Chevron Global Drilling and Completions developed a partnership with Equilibria, who has further developed some of the basic concepts of personality indicators to enhance effective communication, applied leadership, personal and team development, and risk awareness and mitigation. This partnership was formed following a series of incidents that occurred in Nigeria in 2003 on the Sedco Energy SemiSubmersible Drilling rig.

The safety metrics before introducing E-Colors, and trends after, are a clear indicator of the effectiveness of this technique. This has encouraged Chevron Drilling and Completions to begin global implementation, working with Chevron personnel and business partners worldwide through workshops and on-site coaching. The goal is to effectively arm them with, not only the knowledge of the tangible hazards present on each job, but also the intangible hazards that are demonstrated by the E-Colors Equilibria Experience.
4D Reservoir Monitoring and Characterizing of Marimbá Field, Offshore Brazil
Authors: Lima K. T. , Reis V. M. , Malagutti S. R.
Published: February 2011

Understanding saturation and pore-pressure changes is a decisive factor to improve the reservoir monitoring, especially in mature fields. In this paper, we used two 4D data, 1984-1999 and 1999-2005 to the monitoring of Marimbá Field reservoirs offshore Brazil. Its oil production started in 1985 and remains until nowadays. Time-lapse seismic data on this field have been successfully used since 2007 to understand the fluid behavior and identify bypassed oil areas and had helped in decision making, such as drilling development wells on an undrained area or understanding of water saturation increase in wells. Initially it was made a 4D seismic modeling to help interpretation of time-lapse anomalies seen in the field, which suggests that it may be possible to discriminate between oil sands and brine sands both in 3D and 4D data. The two 4Ds data were interpreted, generating important decisions for the field, avoiding expenses with wells positioned in areas already drained. Further, water production diagnostic plots were analysed in order to obtain a quality control for the 4D seismic interpretation, comparing the geological aspects indicated by each method. Following the reservoir strategy for the field, in the last years several wells restorations were accomplished. It consists in the abandonment of inferior intervals washed and completion of the superior intervals. During the field development this explotation strategy faced unexpected water breakthrough in upper interval, due to high permeability channels. It has implied that the workover operations performed in this period has not attained the predicted results because the upper zone was already washed, as shown by the first 4D study. The cross-equalization was only held in 2007, after those unsuccessful workovers. In the same year it was accomplished another intervention, 4D response indicated presence of water in the upper interval in contrast with simulation studies. Workover confirmed the time-lapse response avoiding unnecessary expenses.
Use of Satellite Radar Data for Surface Deformation Monitoring: A Wrap-Up After 10 Years of Experimentation
Authors: Bagliani A. , Mosconi A. , Marzorati D. , Cremonesi A. , Ferretti A. , Colombo D. , Novali F. , Tamburini A.
Published: February 2011

Surface deformation monitoring can provide valuable information in assessing the environmental impact of activities, evaluating volume/pressure changes in a reservoir, as well as estimating other geophysical parameters. Eni and stogit have been studying the use of Interferometric Synthetic Aperture Radar (InSAR) data for surface deformation monitoring since 2001. Based on almost 10 years of R&D and operational projects, this paper aims to summarise the strengths and weaknesses of this space geodetic tool, as well as providing an outlook on future developments in the up and down-stream activities.

During the last decade, satellite InSAR data have been gaining increasing attention for their unique technical features and cost- effectiveness. In particular, second-generation InSAR techniques (e.g. PSInSAR™) are capable of providing thousands of displacement measurements per sqkm at millimeter precision. Since 2001, eni has financed projects based on InSAR data, first for environmental assessment and then for reservoir monitoring. In parallel, stogit has used these techniques for the standard monitoring of gas storage fields. Projects and results have followed as a result of the development of InSAR technology. Radar data were first validated, compared with optical leveling surveys, integrated with GPS data, and then used for geophysical inversion, in both local and regional analyses. For some areas, data have been gathered by two different satellite platforms, providing unique datasets for a thorough analysis of different data sources. Long-time records of injected/extracted gas volumes, together with a multi-year displacement data set, have allow the calibration of fluid-dynamic and geo-mechanical models, that can be used to investigate the effects of increased working gas volumes, especially in overpressure conditions, in natural gas storage fields. In the authors’ opinion, InSAR data will become a standard tool for reservoir monitoring in the next few years. The experience summarised in this paper can provide a useful contribution for petroleum engineers and the oil&gas community in general.
Application of a Coupled Wellbore/Reservoir Simulator to Well Performance Optimization
Authors: Livescu S. , Brown W. P. , Jain R. , Grubert M. A. , Ghai S. S. , Lee L. W. , Long T. A.
Published: February 2011

Long-term completion performance is important for the economic development of any field. As fields are now developed in environments that are capital intensive and increasingly technically challenging, new technologies are required for optimization of the completion design. Stand-alone reservoir simulators lack the required detail on the completion side, while stand-alone wellbore simulators do not have the long-term reservoir performance information available. Even the new class of coupled wellbore/reservoir simulators often lack comprehensive completion design capabilities. We have developed a fully-coupled black-oil wellbore/reservoir model which accounts for the necessary details for an optimized completion design. Specifically, the model couples ExxonMobil's proprietary reservoir simulator and a detailed completion hydraulics simulator such that the reservoir flow, wellbore tubing and annulus flows, and pressure fields are simulated simultaneously.

In this paper, we compare different synthetic cases involving open-holes, pre-drilled liners, packers, and inflow control devices that demonstrate unique completion opportunities captured by using our modeling capabilities. We show that our model provides not only detailed information regarding the tubing and annulus flow and the associated pressure drops along the completion, but also the impact of different completion types on short- and long-term reservoir recovery. Our results show the significance of this new coupled approach in its ability to relate the reservoir performance and the flow dynamics through various completion types.
Gravel Pack Imager Tool (GPI): Precise and Accurate Knowledge of Gravel Pack Integrity
Authors: Hertzog Russel C. , Smaardyk John E. , Steinman Donald K.
Published: February 2011

Wood Group Logging Services in collaboration with a major international oil company has developed a new logging tool for gravel pack inspection that is the first tool to collect azimuthal and longitudinal information simultaneously. The tool uses gamma ray scattering to investigate the integrity of the pack close to the screen. It has six detectors that investigate 6 azimuthal segments simultaneously. Included in the tool is an orientation sensor so that all measurements are referenced to the high side of the borehole. This tool is sensitive to voids as small as one inch along the axis of the borehole and voids less than ½-inch in the pack radially from the borehole. The region of investigation is approximately two-inches from the tool, and there is no significant response to materials behind casing. Therefore, the readings are immune to variations in cement thickness and formation density.

Initial development of the tool was performed using the Monte Carlo nuclear modeling code, MCNP. Tool prototypes have been tested in sand-pack fixtures built specifically for this project. In addition, field tests have begun in a Wood Group Logging Services test well. Data from the prototype tool in test fixtures were used to validate and benchmark MCNP simulations. Completion fluids with densities from fresh water to 14.5 pounds per gallon were tested, and the tool responds well regardless of fluid. These results provided a high degree of confidence that tool response corresponded to actual conditions.

The GPI tool can be run on a wireline or in memory mode in combination with collar locator and gamma ray tools. The tool runs centralized in the borehole. The paper shows examples of the calculations, test fixture and field test results. In addition, sensitivity to nominal environmental effects such as temperature, eccentered positioning, and borehole axis orientation are discussed.
Employee Engagement Initiatives to Enhance National Engineering Staff Development
Authors: Kane M. P. , Stanley F. O. , Seymour R. G.
Published: February 2011

Companies have the challenging imperative to develop National staff in key positions in International locations. Systematic development is required to supply appropriate employee development to meet government mandates, customer demands and to reduce expenses of running operations internationally.

This paper will outline engagement initiatives that improved the participation in and promotion of National Engineering staff in the Asia Pacific Region and present successful strategies for the petroleum industry to meet the outlined requirements.

The study outlines initiatives employed to engage and motivate Engineering employees to participate in the company's Engineering Development Program. The Technical Career Advancement Program (TCAP) was launched internationally in 1998 (Wilke and Hoskins, 2001). It was not an immediate success in Asia Pacific Region (APR), and other International locations, despite guaranteed remuneration increases with progression. An investigation revealed limitations to the success of the program: A general malaise and lack of interest in the programDifficulty of engineers’ scheduling to attend classroom training due to operational requirementsPoor understanding of program policies and proceduresPoor uptake of On Line training by engineersLack of understanding of what was required by each Engineer to progress in the systemPerception of a lack of promotions and remuneration given for previous participation in the Region

The APR management initiated a number of strategies to; promote the program, the scheduling of classroom training, simplify the process of accessing on line training and understanding the steps required and strongly promoted the successes of other Engineers to encourage overall participation. The success of these initiatives has dramatically changed the effectiveness of this Career Advancement Program (CAP) in APR. The number of expatriate Engineers has reduced, and now more than 50% of the National Engineers had promotions and salary increases in FY08 and FY09.

The success of these initiatives will offer possible solutions for other companies to employ in Nationalization programs in International locations
Design Considerations of Information Systems to Support Employee Development
Authors: Kane M. P. , Stanley F. O. , Seymour R. G.
Published: February 2011

Development of competency in operational employees is vital in the Oil and Gas industry for quality of safety, service, and, employee retention. This paper outlines key considerations in the design of information systems to meet all key stakeholders requirements to ensure success of such an application in employee development.

These considerations are needed to ensure the Competency Based Management System (CBMS) engages employees, delivers useful and meaningful reports to management, and has the ability to meet the industry's future requirements. The steps outlined in the paper have applications for competency, safety, learning and development and the performance management of employees.

This paper outlines the key stakeholders involved in designing information systems for staff development. The CBMS need to record progress, store evidence, and to give management and administrators meaningful and relevant reports.

A major international service company will present how it uses a Career Advancement Program (CAP) for a number of key operational and engineering employees. These CAP's guide an employee in the competencies and training required to advance in their career as an operator, engineer, supervisor, etc. The success of the roll out of these programs has been limited in part due to the time constraints placed on managers to engage employees and track progress.

The Information System is a Computer Based Management System, CBMS, for the CAP program. This dramatically increased the employee participation. It also reduced the time requirements placed on management and administrators. The CBMS gives in depth analysis and measurable reporting of the employee development in both country and regional levels. The most critical component was the employees’ ability to recognize the CAP requirements, to access the information required for each progress, and to track their progress.

In the design of such CBMS solutions, careful consideration of the needs of employees, managers, administrators, and managers is necessary. Considerations included security access, edit rights, required information to be included, differentiate service line requirements and employee function, the ability to store supporting documentation, reporting requirements, and ability to get an overview and drill down into individual records.

The Asia Pacific Region now uses the CBMS solution. The success of this system, based on considerations outlined in the paper, has expanded its deployment into the Middle East, Europe and Africa, and in the near future Latin America.

The aim of the paper is to present a decision-making matrix that will support the successful development of information system solutions in the Industry.