RAISING EXPECTATIONSQUANTITATIVE UNCONVENTIONAL RESERVOIR CHARACTERIZATION ENABLED BY BREAKTHROUGH SEISMIC TECHNOLOGY Presented by J. Quigley (Schlumberger)

In recent years thin, tight reservoirsboth sand and carbonatehave represented two important types of hydrocarbon exploration and development targets in Jurassic strata in central, northwest, and northeast areas of the Sichuan Basin. Most production from these onshore areas has been closely associated with numerous small faults, fracture corridors, and micro-cracks in thin carbonate layers; and in high-porosity zones in tight, thin sand bodies. With reserve estimates for the Sichuan Basin most likely higher than current estimates, demand for increased production from the area has made it imperative to perform reservoir characterization with the highest possible accuracy.

This presentation discusses a case study in which seismic characterization of Sichuan thin, tight sand reservoirs was dramatically improved through use of a state-of-the-art, high-density, full- azimuth, point-receiver land seismic survey, calibrated with well log data. The method used involved a comprehensive data-processing sequence utilizing algorithms developed for the high- density, full-azimuth applications. Quantitative reservoir characterization was achieved by well log data correction, rock physics analysis, simultaneous amplitude-versus-offset (AVO) inversion and lithology identification. Specifically, we have been able to successfully delineate the geometry of the hydrocarbon bearing sand channels. Quantitative multiscale fracture characterization was also achieved by simultaneous azimuthal AVO (AVOaz) inversion and seismic post-stack ant-tracking. The resultant dataset has provided a radically different view of the subsurface reservoir that was previously unseen and will enable future drilling decisions.

HOW TO IMPLEMENT A SUBSURFACE INTERPRETATION SYSTEM WHILST MINIMISING BUSINESS IMPACT Presented by D. Hodgson (Woodside)

Making the decision to move from an ageing subsurface interpretation platform to a modern platform with additional benefits is a relatively easy decision to make. Moving from the old to the new however is not straightforward and is something E&P companies will typically undertake once every 10-20 years. Changing the software applications is just one element of change needed to successfully complete the move. Other factors such as corporate capability, operating processes and supporting technology are key ingredients. Moving the mountain of corporate data is not a simple cut and paste exercise.

How do you make such a transition without major disruption to Exploration and Development activities and allow users to deliver on work commitments. This presentation will highlight the key ingredients needed to make a successful transition to Petrel and Studio applications with a particular focus on Geoscience and best practices in data management.

RESERVOIR CHARACTERIZATION DEEP WATER WELLS (20112013) Presented by T. Martinez (Pemex)

New challenges in Deep Water Reservoirs are facing in PEMEX Activo de Exploracin Aguas Profundas Norte (AEAPN) with the need to incorporate new oil reserves that contribute to the production that Mexico requires. In order to accomplish this goal an accurate Reservoir Characterization is need it for reserve certification, a large amount of information such as logs and cores from new Wells, 3D high-resolution seismic, 3D EM data, making cutting edge technological solutions necessary.

Inside Perdido fold belt area are the first successful wells for AEAPN and the first oil producers on Depth Water environment in all Mexico. The Structural and Stratigraphic complexity encounter on these fields required a Characterization Model able to reproduce thin layers geological behavior in order to be representative by 3D model in an accurate way, challenging the number of cells necessary modeling the fast variation of petrophysical properties on vertical direction.

Create 3D models with enough level of detail considering that areas to be modeled are around 1000 km bring new challenges to handle the number of cells necessary modeling the New Reservoirs, making necessary the combination of Technology in software and software as well as advance geological knowledge.

PEMEX Need to incorporate New Reserves bring an opportunity for Characterization group to innovate the way that 3D Reservoir Models are build it, using the same Technology across the life of the well, starting the characterization preparation phase together with well drilling surveillance and updating this model as new data arrives from well, reducing the amount of time need it to deliver a reserve certification when well is finished, the successful way to achieve this it with the precise combination between Technology and People knowledge, that will be described on this Document.

INTEGRATED PLAY AND PROSPECT ASSESSMENT IN EXPLORATION Presented by A. Acevedo (Schlumberger)

The most critical decisions in exploration aim to answer three questions: which acreage to acquire, which prospect to drill first, and where to drill the first well on each prospect. Traditionally, the answers are based on geological interpretation, risk assessment, and economic evaluation of exploration projects. However, often these assessments are performed by different teams and by using disconnected technology. The latter leads to issues with time efficiency and more critically, may lead to decisions taken out of context. We introduce an integrated play to prospect risking approach. This empowers you to perform full geological evaluations linked to maps, interpretations, and the risked economic models, while remaining spatially referenced.

MITIGATING GEOMECHANICAL RISKS IN YOUR ASSETS Presented by A. R. Herrera (Schlumberger)

Many reservoirs in the world can experience geomechanical issues. These can affect the reservoir drive mechanism, create damaging stresses on wells, and potentially breach the cap rock of the reservoir. This demonstration will show how a combination of the Petrel and Techlog platforms, and the Eclipse and Visage simulators are used to address and mitigate these risks through the use of mechanical earth models coupled to reservoir simulators. It will be shown that reservoir performance can be more realistically evaluated, the risks to long-term well survivability identified, and a drainage strategy created to reduce the strain on the cap rockall during the field-development phase.

A 4D GEOMECHANICS SOLUTION APPROACH TO NATURAL FRACTURE PREDICTION IN OPERATION Presented by Xavier Legrand (PETRONAS)

Since the Seventies, Exploration and Production challenges in Sundaland regularly lead to improved understanding of its tectonic setting. According to land-based geologists this region was previously considered as tectonically stable and did not exhibit any evidence of far-field deformation. Currently, the Malay basin located East offshore of the Malay Peninsula is known to have undergone a succession of major tectonic events. The basin originated in the Late Cretaceous and was developed through structural changes consistent with a polyphase extrusion model and displacements in which India has successively pushed Sundaland (Tapponnier et al., 1986). Initially, the extrusion imparted sinistral transtensional wrenching on the axial basement fault along the basin length. In post Mid-Miocene, wrench slip reversal produced transpression, accompanied by a positive structural inversion. At present day, this complex tectonics confers to the basin a singular fracture model through time.

A natural fracture prediction (NFP) study is used to depict the fracture model associated with the tectonic calendar. An innovative geomechanically-based methodology describes the different steps to reduce uncertainty in the natural fracture zone assessment both in estimating (i) the paleo-geometry of the structures from a 2D & 3D geomechanics-based reconstruction (Maerten and Maerten, 2006) and (ii) the paleo-tectonic stresses, recovered by a fracture clustering based on Andersons theory of faulting (Anderson, 1942), and used in the geomechanical simulations from the inversion technology (Maerten, 2010). As a consequence, the understanding of the reservoir characterization was greatly improved.

References

Anderson, E. M. [1942] The dynamics of faulting and dyke formation: with applications to Britain. Nature, 149, 651-652.

Maerten, F. [2010] Geomechanics to solve geological structure issues: forward, inverse and restoration modeling: Ph.D. thesis, page 450, University of Montpellier II, Montpellier, France.

Maerten, L. and Maerten, F. [2006] Chronologic modelling of faulted and fractured reservoirs using geomechanically based restoration: Technique and industry applications. AAPG Bulletin, 90, 1201-1226.

Tapponnier, P., Peltzer, G. and Armijo, R. [1986] On the mechanics of the collision between India and Asia. From Coward, M. P. & Ries, A. C. (eds), 1986, Collision Tectonics. Geological Society Special Publication, 19, 115-157.

PRODUCTION AND INJECTION MONITORING AND SURVEILLANCE MYSIP Presented by O. Agudelo (Ecopetrol)

The Casabe Technology Alliance between Ecopetrol and Schlumberger started its operation in 2004 in Casabe field. The field came originally into production several decades ago and by 2004 was producing close to 5,000 BOPD. The alliance went into a re-development of the field with an aggressive strategy to increase Oil production through selective water injection for secondary recovery. The re-development considered a significant increase of producing and selective injector wells, something that poses a challenge in terms of injection and production data handling, engineering worklfows for better decision making. Casabe Alliance decided to implement an integrated operation decisional system for supporting key production and operational business processes bringing to end-users the right information at the right time for better decision. The scope includes not only automation of some business processes along with the underlying system but also the business change management activities for managing the change.

This project consists in adjusting operational processes, in providing different component to implement as:

1. Component 1: Data Management

Data consolidation and creation of only one and unique data

source of information for CASABEs asset historical production.

2. Component 2: to-be Production business processes and mapping of information flows.

Analyze and document the current injection / production process,

which allow identify improvements related to data management

3. Component 3: Production information and engineering workflows Management

Expert Automatic System Intelligent workflows based on pattern recognition.

Data visualization and alarms generation.

Link operational Data Base with the other applications

Ensure data quality for the follow up and

analysis. The key benefits for the Casabe Alliance are:

Decision making process Improvement that should impact OPEX (reduction) and Production (increase)

Protect the historical data: Accessibility, tracking , integration of in a timely

manner Surveillances focus in production and Injection wells (manifolds)

Effective water flooding control

Timely decision from current and reliable information

Data transfer to internal and external applications with limited human manipulation

MODELLING AND OPTIMISATION OF GAS STORAGE AND PRODUCTION SYSTEMS Dr Bishop Falope (PetroFlow)

Gas production, storage and injection facilities are an economical way to sell gas when price is right and store when prices are unfavourable. Operating a gas production and injection system combines the challenges normally associated with wet gas production i.e. hydrate and liquid management, with the need to be able to switch from production to injection modes to at short notice. In order to simplify the complexity associated with operating such facilities, operators adopt simply and easy to follow procedures. This however comes at the expense of optimal operation due to the adoption of very conservative criteria.

This paper presents the use of OLGA for simulating the operation of a production-injection facility using compositional tracking. The model was constructed to allow production and injection to be modelled with a single model and was benchmarked against transient operating data provided by the client. The remarkable representation of the facilitys operation by the model led to its use for significantly simplifying the operating procedures and allowing decisions to be made more easily and cost effectively. The model was further used as a virtual temperature sensor taking the place of a damaged sensor.

The results of this analysis show how the full benefit of simulation can be realised for operations support, asset performance optimisation and cost saving.

PETROLEUM PROSPECTIVITY OF PAKISTAN WITH SPECIAL REFERENCE TO EXPLOITATION OF UNCONVENTIONAL HYDROCARBON RESOURCES AND ITS CURRENT STATUS Presented by Moin R. Khan (Pakistan Petroleum Limited)

The presentation will give an overview of Pakistans existing E&P scenario vis--vis its vast sedimentary basins and the huge conventional and unconventional hydrocarbon potential these basins offer.

The global energy scenario has been evolving with declining production in the face of rising demand for both oil and gas. As a result, reserves replacement ratios are going down and currently stand at less than 50 percent. This means that the current global trend in energy supply and demand is patently unsustainable. In addition, the gradually rising gap between demand and supply of oil is filled mostly by gas and, more recently, unconventional energy resources. At the projected growth rate, the world will need to find new reserves, ensuring additional production to the tune of 42 MMboepd by 2035 on account of depleting reserves from large fields, both new and old, and future growth requirements.

Pakistans Exploration and Production scenario is not very different despite the fact that energy consumption in the country has grown at an average rate of over 5 percent per year during the last 15 years, which is one-third of the world average. As such, the country is struggling to meet growing energy demand in the face of fast-depleting oil and gas reserves, high oil prices and escalating capital costs.

Since 2006 2007, energy supply has been unable to fulfill demand. And as new reserves have not been discovered at the desired rate, the gap is continually rising. So far, 56 Tcf of gas and about a billion barrels of oil have been discovered in 242 oil and gas fields through 780 exploration wells with a success ratio of 1: 3.3 wells, which is very high compared to world standards.

The trend for Pakistans oil and gas discoveries called the creaming curve indicates that size of discoveries is progressively decreasing despite an increase in success ratios resulting in a large number of discoveries. However, this creaming curve represents only that part of the country where exploration activities have been focused. Drilling of 780 Exploration wells in a sedimentary area of over 800,000 Sq. Km is too little by any standard. This makes it imperative to accelerate the exploration efforts for both conventional and unconventional resources to meet present and future energy supply challenges. This is to say that exploration for unconventional hydrocarbon reserves, which is an integral part of the energy mix in North America, a game changer in that region, and on which very little concrete work has been done in Pakistan, deserves special attention.

As such, increased focus is required on unconventional reserves such as tight and shale gas to meet present and future energy supply challenges. This is to say that exploration for unconventional hydrocarbon reserves, which is an integral part of the energy mix in North America, a game changer in that region, and on which very little concrete work has been done in Pakistan, deserves special attention. Quite developed in North America, this is an emerging play type in the rest of the world and holds great promise for Pakistan too. The North American model can be replicated in Pakistan if an operational synergy and the economies of scale is created.

If 56 Tcf and one billion barrels of conventional gas and oil reserves respectively have been discovered, there has got to be organic rich shales (known to be of Early Cretaceous and Paleocene age) that have generated at least 10 times that much gas/oil, 50% of which would have been retained by these rocks. Based on conservative estimates, unconventional reserves of Tight and Shale gas in the country stand at about 100 Tcf. Similarly there are known tight gas reserves of 38 Tcf that needs immediate exploiting, while the potential reserves estimates are close to 100 Tcf. Shale gas is expected to be associated with Shale Oil. This is clearly not the kind of statistics that we can afford to overlook any longer if we are to ensure the countrys future energy needs. To this end, it is imperative for geoscientists, petroleum engineers, service providers and policy makers to strategize together and chalk out the roadmap for a way forward.

ROCK PHYSICS & SEISMIC INVERSION TO CHARACTERIZE A TIGHT GAS SAND Presented by Jorge I. Adrian (PetroSA)

A reservoir is exposed to a great number of analyses in all stages of its active life (exploration- appraisal-development-enhanced recovery) in order to optimize the asset value and to reduce the uncertainly of geological and production factors. Seismic data has come to rule an essential role in this process. However, seismic has a limitation: It represents an interface property, instead of a rock property, so in principle the seismic data is inverted into a volume of elastic properties such as Acoustic Impedance, VP/VS, etc. The remaining challenge is to understand the elastic response to changes in petrophysical properties (porosity, lithology, hydrocarbon saturation, etc.). In order to address this dilemma, rock physics modelling has been undertaken.

The broad objective of this presentation is to show a methodology to characterize in PETREL a tight Gas Sand reservoir based on 2-main steps:

(a) To perform in situ and perturbational log derived rock physics forward modelling to understand the effect of varying fluid fill, porosity, clay content and thickness; and study the AVO attribute responses to help determine which, if any, AVO attributes or cross plot products may be useful to discriminate between pay vs wet targets or lower and higher porosity, etc.

(b) To invert seismic reflection data into quantitative elastic-properties (Pre-stack inversion) to sufficiently differentiate geological features with similar P-impedance signatures. This method uses multiple angle seismic partial stacks and their associated wavelets as input to generate P-impedance, S-impedance and density as outputs.

The study area is situated off-shore South Africa, in water depths of less than 200 m. The target reservoir is the Early Valanginian gas bearing sandstones in the Upper Shallow Marine unit.

OVERVIEW OF THE CHALLENGES TO EXPLORATION POSED BY DEEPWATER SHALLOW HAZARDS AND SALT IN THE ATLANTIC BASIN Presented by J. Dribus (Schlumberger)

At the end of the Permian Period over 250 million years ago, the supercontinent of Pangea began to be rifted into the smaller continents we are familiar with today forming the Gulf of Mexico and then the greater Atlantic Ocean basin. This talk reviews the geologic evolution of the Atlantic basin and the filling of parts of the basin margins by layered evaporate complexes in Brazil and across the conjugate margin in Angola, and massive halite deposits within the Gulf of Mexico.

This talk also reviews several of the key exploration challenges posed by shallow hazards in the deepwater operating environments, and discusses additional drilling hazards created by massive salt and layered evaporates, including possible problems drilling into, through, and out of salt (such as cap rock, inclusions, rubble zones, and feeders).

WELL PLANNING AND RELIEF WELL SIMULATION Presented by S. Forsyth (Schlumberger)

Designing wells in the Petrel E&P software platform has changed, with new trajectory algorithms, a user-friendly design interface, and driller-friendly spreadsheets. Trajectory uncertainties associated with surveying equipment have also been implemented, taking well design to the next level.

Relief well simulation focuses on the new screening facility available in the Petrel platform for relief wells, using the pumping, trajectory, construction, and mud parameters to perform a dynamic multiphase simulation to assess the outcome of the well kill operation, before the original well is even drilled.

IMPACT OF SUBSURFACE AND SURFACE MODELING FORECASTING PRODUCTION Presented by D. L. Clements (Schlumberger)

The cost of deepwater wells reduces the number of appraisal wells drilled. Therefore, when developing a deepwater field, the information collected in the reservoir may be limited. This demonstration will examine how the uncertainty in the reservoir will impact the field.

ADVANCES IN STRUCTURAL INTERPRETATION Presented by G. Van Der Hoff (Schlumberger)

Structural interpretation of the subsurface is a fundamental process in the E&P lifecycle, as accurate interpretation of geological structures are the building blocks for velocity modeling, property modeling, assessment, and risk analysis of hydrocarbon volumetrics. In complex geological regimes, making a fast and confident structural interpretation is a significant challenge.

In this presentation we will demonstrate how advanced structural interpretation in the 2014 release of the Petrel E&P software platform redefines conventional structural interpretation workflows by efficiently combining manual and automatic interpretation approaches, complimented with comprehensive QC tools to easily correct wrong interpretation in a user environment that delivers a step change in productivity.

Most importantly, tectonic and depositional relationships can be incorporated through interactive seismic reconstruction based on geomechanical principles, followed by modeling-while- interpreting, which provides a powerful tool for fast and accurate interpretation. This reduces interpretation uncertainty and delivers a confident, validated structural framework of the subsurface that can be used directly in subsequent workflows such as property and fracture modeling, as well as volumetric workflows.

DEVELOPING ASSETS: AN INSIGHT INTO HIGH-RESOLUTION MODELING Presented by J. Quijano (Schlumberger)

The industry is developing many complex fields, which require a large amount of capital investment and often do not perform as expected or are delivered behind schedule. Today, there is a greater understanding of the structure, geology, and fluids. This presentation will show how the INTERSECT high-resolution reservoir simulator uses this greater understanding to provide more accurate forecasts of recoverable reserves, production forecasts, and fluid breakthrough, which form the essential cornerstone to developing complex fields.

UNCERTAINTY TO ECONOMICS: INTEGRATING DYNAMIC SIMULATION AND ECONOMIC MODELLING TO MAKE BETTER DECISIONS Presented by Russell Julier (BG Group)

A Petrel RE to PEEP plug-in has been developed by BG Group in partnership with Schlumberger to allow project cost, subsurface and economic uncertainties to be considered in a single integrated environment.

The presentation will demonstrate an end-to-end Uncertainty to Economics workflow that integrates Schlumbergers Petrel RE and Eclipse products with the Schlumberger Meraks PEEP product. Discuss why BG Group developed the workflow and supporting plug-in and the advantages the workflow brings to the assessment of uncertainty and decision making.

The widespread implementation of multi-realisation geological and reservoir simulation software has transformed the subsurface workflows used of many operators. The ability to incorporate uncertainty and multiple alternate subsurface realisations has allowed a better understanding of the resource risk profiles associated with new opportunities to be developed. This is particularly important during the appraisal and pre-sanction development phases where the ability to create value is at its greatest.

However, much information is lost when relatively few discrete cases from the full resource distribution are taken forward for detailed economic analysis allowing only a partial view of a project NPV risk profile to be created and preventing the economic impact of many uncertainties to be fully considered.

The incorporation of an economic model within an automated workflow potentially offers a significant improvement in both quantity and quality of information available to decision makers by allowing the many more realisations to be evaluated economically and the full risk NPV risk profile to be described.

This integration is achieved by the near concurrent running of multiple realisation Petrel RE static and dynamic models together with the PEEP economic model to calculate economic KPIs using the Plug-in.

Subsurface, Project (Cost) and Commercial (Price) uncertainties can be considered within a single environment to provide multiple discrete NPV values for sensitivity, decision tree analysis and Monte Carlo analysis.

The automated use of existing PEEP economic models via the Petrel RE-PEEP plug-in thus offers increased efficiency, better understanding and improved decision making.

HOW TO BUILD A DATA MANAGEMENT PROGRAMME Presented by Fabio Feneri (Eni)

It is well known that the maintenance of quality information leads to a higher probability of finding hydrocarbon reserves and a reduced cycle time. As part of our on-going cycle of continuous improvement eni recently commissioned Schlumberger to assess the overall management of corporate data across the global exploration function. This assessment detailed processes and workflows in the headquarters, in selected affiliates and in the way those entities interact.

Following on from the recommendation made by Schlumberger in the assessment eni are now on course to re-engineering several of our global processes with a view to providing an overall increase in efficiency and of improving information quality world-wide.

STUDIO CUSTOMIZATION, IMPLEMENTATION AND CHALLENGES Presented by D. Aziz (Petronas)

In 2010, PETRONAS has defined Petrel as their foundation platform for G&G and RE community. This is to ensure the flow of information will be on the same platform, from seismic to reservoir. The amount of information and knowledge that travels through the eco-systems are enormous. The needs to streamline data management workflows and capturing knowledge - has to be done via Studio.

PETRONAS started to access Studio back in late 2012 and the deployment started 6-months later. Studio has to be designed to suit the three main PETRONAS E&P business units Explorations, Development & Regulator. The deployment involves development of process to streamline data workflows, managing users and data.

This paper will illustrate the journey that PETRONAS undertake to adopt Studio in its organization, as well as, highlighting some of the challenges facing the team.

OUR G2 E4 UNCONVENTIONAL FIELD DEVELOPMENT METHOD Presented by Steve Geetan (EP Energy Corporation)

In todays fast cycle Unconventional field development, the drilling and completion design steps are mostly done independent of a 3D geological model or a deformable 3D geomechanical model. Dynamic reservoir simulation is commonly done using models not informed by a well constrained geologic model and when done are mostly single well simulations due to the computational cost in simulating a multi-well fracture volume. Moreover when available, the geomodels are normally built after the drilling and completion of the important pilot phases of an unconventional development. These disconnect among the key disciplines causes a disruptive learning cycle which can easily erode value.

The G2 E4 workflow starts with a geologic property model and a discrete fracture network (DFN) using seismic and or well centric data (image logs, core, and specialized gas logs such as helium). These results then feed the 3D Mechanical Earth Model (MEM) where the DFN features are used to perturb the wellbore scale stress field. Using observations from the drilling experience, the completions hydraulic fracture treatment pressures and the effects of producing the reservoir over time we can calibrate the model through many feedback loops improving its reliability even when initially built with measurements that have high uncertainty. This is achieved by fast numerical simulation allowing many calibrating experiments to be performed when selecting the geomechanical parameters.

The resulting 3D MEM allows us to build multi-well models providing significant insights into well interference, order of fracturing wells and stage spacing by numerical simulation of the evolving stress field. This method provides a strong link between the geoscientists and engineers allowing all observations to be integrated, bridging the gap among these disciplines and improving chance of success.

ASSET OPTIMIZATION SOLUTIONS TO ENHANCE RATES, RECOVERY, AND EFFICIENCIES Presented by Kirk Pitts (Schlumberger)

In field development planning, the best industry practice is an integrated asset approach. The same best practice applies in the production phase, in which the aim is to maximize value extraction. This is done through asset optimization, which means simply doing better tomorrow than is being done today. This involves making decisions to improve field performance in a live operating environment, in which software is connected to the field to better understand the surface/subsurface.

However, asset optimization is more than just technology: it is the ability to see online information, to understand the state of the field, and to use software systems to analyze and make the right decisions to improve recovery and hit target ratesefficiently. This presentation will cover the asset optimization offering from Schlumberger. It will expand on how our multifaceted approach integrates technology, information, people, processes, and organization to maximize asset production performance with a balanced view across the entire hydrocarbon pathway.

BUILDING GEOLOGICAL MODELS IN EXTENSIONAL AND COMPRESSIONAL SETTINGS Presented by C. Chahine (Schlumberger)

The simplest structural and stratigraphic traps have mostly all been found. Today, E&P companies are increasingly exploring for and producing hydrocarbons in more and more complex geological environments. To reduce risk and maximize return, new techniques are needed to produce a reliable representation of the subsurface that can be integrated from interpretation to simulation.

The main challenges in this complex area are often related to the numbers of faults and the relation between them, as well as handling complex reverse faulting or thrust. Associated to any of these cases, the variation of thickness of the geological formation and the handling of multi-z formation are also challenging and often not handled very well with the conventional modeling methods. In these areas, understanding the relationship between the faults, formation, and the associated timing is critical. It is clear that to be able to do this efficiently, having separate workflows for interpretation and geological model construction is not an optimal approach and leads to inaccuracy and repetition.

Today, the volume based modeling approach within the Petrel E&P software platform helps to tackle each of these structural and stratigraphic challenges, while simultaneously integrating the interpretation and model-building process. This presentation details complex examples from extensional and compressional provinces, showing how they have been handled in the Petrel platform from the interpretation to the gridding.

SEISMIC DEPTH IMAGING COLLABORATION BETWEEN STATOIL AND WESTERNGECO Presented by Mike Cogan (Statoil)

Successful seismic imaging is critical to Statoils exploration success in many basins, particularly the Gulf of Mexico, Angola, and Brazil where there is considerable geologic complexity. While all exploration work requires seismic data for interpretation and sometimes, lithology and fluids prediction, in the most complex geology, seismic images are even more important. It is therefore particularly frustrating that the seismic image tends to break down exactly where it is most needed. Examples from the Gulf of Mexico abound where a prospects trap geometry is highly uncertain because overlying salt formations refract, mode convert, and scatter seismic energy, leaving, noisy, washed-out images.

A decade of advances in seismic acquisition (wide and full azimuth marine data, broadband) and seismic imaging technologies (true 3D demultiple, reverse time migration depth imaging, full waveform inversion, anisotropic velocity model building) have made an impact on our understanding of the subsurface. There are many examples of the compounding effects of these new technologies, but with better data, exploration has progressed to deeper targets and more complex geology, where the improvement from the latest technology is often localized, with many important areas still poorly imaged. In the Gulf of Mexico, the recent increase in activity in deep water Paleogene targets is a good example.

How will the current set of challenges be solved? Some progress is being made by understanding the problems and making better assumptions. Rock physics information and basin models are being used successfully to constrain velocity model building efforts. In some areas, subsurface understanding comes from incremental improvements in seismic images achieved by iteratively testing plausible scenarios (geologic models). Seismic imaging workflows that incorporate geologic constraints and multiple forms of non-seismic data can help drive us towards the best image. Seismic imaging algorithms and the high performance computers they run on have to be both accurate and efficient to produce images from models in hours instead of days.

Statoil and WesternGeco are collaborating to solve complex imaging challenges in Statoils Houston Seismic Imaging and Processing center. This presentation will provide a look back on two years of the Omega/Petrel Imaging solution in Houston, what both companies have learned, and new directions for the future.

INTEGRATED APPROACH TO PETROLEUM SYSTEMS MODELING IN UNCONVENTIONAL PLAYS Presented by A. Madhoo (Schlumberger)

In recent years, as North America has led the way to full, large-scale commercial production of unconventional oil and gas, the exploration industry has benefitted from high well counts and generally, dense networks of onshore subsurface data. Europe, on the other hand, has a low existing well count for conventional resources and notable socio-political and infrastructure challenges, such as high-population densities. Success, therefore, relies on using all existing data and drilling a reduced number of exploration wells.

An integrated 3D geological and petroleum systems model of the onshore Netherlands is presented, which includes critical spatial information such as geographical terrains and surface constraints. Results from this approach clearly demonstrate areas of higher prospectivity, and, importantly, their associated uncertainty. This allows E&P companies to select areas that have the best chance of success.

CONCEPTUAL TO DETAIL ENGINEERING OF THE PRODUCTION SYSTEM Presented by W. Oliveira (Schlumberger)

Subsea capital expenditure is forecast to double over the next five years, in line with the development of more complex subsea fields in deep water. This presentation will address how Schlumberger software enables engineers to assure flow from pore to process through the conceptual and detailed design, using steady-state and dynamic simulationaddressing challenges such as lift requirements, thermal management, and operability, and thus providing the best return on the capital investment.

HOW TO LEVERAGE YOUR INVESTMENT IN PEEP TO DO DECISION ANALYSIS AND PROBABILISTIC ECONOMICS Presented by Bernardo Gurfinkel (Hess Corporation)

At Hess Corporation, we have been using Merak Peep with FML (Fiscal Model Library) as our core economic engine since 2007. One year after the implementation, we developed our first Merak Peep extension called The Budget Tool that optimized the workflow for the capture of project level production, capital expenditure, reserve migration, and economic data for all our Production and Developments assets.

Since then, the need for economic services has grown dramatically within Hess: we now self- certify reserves, the number of wells to be evaluated has increased in tandem with our unconventional portfolio, and senior management now requires more probabilistic based analysis.

In order to meet this growing demand the company implemented the Hess Economic Suite (HES) in 2011. HES was built over 4 basic pillars:

1. A "cloud" based platform that reduces calculation and response time by running, when possible, economic cases in parallel.

2. Merak Peep as our global economic engine.

3. An App framework that lets us implement new workflows faster.

4. A Plug and Play philosophy to leverage 3rd party software.

This presentation explains how Hess has leveraged HES and its Peep investment to do decision analysis and probabilistic economics. It describes the different workflows being used and what challenges still remains.

3D ELECTRICAL RESISTIVITY DATA PROCESSING IN PETREL BY IERP Presented by O. Tokareva (CJSC Irkutsk Electroprospecting Company)

Methods other than seismic are becoming ever more actual in petroleum exploration, among them advanced electromagnetic survey. Being complementary to seismics, the advanced electromagnetic survey can identify subsurface structure and its parameters in depth range from a few meters to kilometers and reduce well placement risks by constraining reservoir locations and fluid type.

CJSC Irkutsk Electroprospecting Company (IERP) is the only Russian service company to offer joint processing of resistivity and seismic data in Petrel, which opens new capabilities in reservoir characterization. Converting geoelectrical parameters to the universal SGY format with a specially designed technique allows integrating resistivity data into geological modeling in Petrel. Geoelectric patterns have implications for lithology, reservoir zones and their saturations, and presence of igneous rocks and faults. Either 2D or 3D resistivity data can be used at different exploration phases. With 3D data, cubes of geoelectrical and seismic attributes can be created.

The partners and clients of IERP are the leading operators and service companies around the world, such as PETRONAS, PrizePetroleum, Gazprom, Gazpromneft, Novatek, Surgutneftegaz, Irkutsk Oil Company, Institute of Petroleum Geology & Geophysics and SNIIGGiMS Institute (Novosibirsk), and others.

The efficiency of IERP technologies have been proven in extreme weather and climate conditions in Northern Russia, India, Saudi Arabia and Southeast Asia. The experience of using Petrel for 3D resistivity data processing is illustrated with examples from East Siberia (Russia), Borneo (Malaysia), and Sumatra (Indonesia).Resistivity survey was successful in resolving structural and oil-gas exploration tasks in various geological conditions. Comprehensive analysis of Vendian clastic reservoirs based on resistivity and structural patterns has improved prediction quality for East Siberian prospects. Resistivity data can be the only source of structure information in the cases when seismic data quality is low.

CHEMICAL EOR SIMULATION USING ECLIPSE Presented by Mehdi Izadi (Tiorco)

Short overview of Chemical Enhanced Oil Recovery (CEOR) technologies including; Surfactant, Polymer, Thermally active polymer (Bright Water) will be presented. Main key laboratory data required for modeling each technology and how Eclipse was used in utilizing laboratory data, and model these technologies will be addressed. The presentation would also include core-flood history matching using eclipse and a how the laboratory model can be scaled up to full field scale simulation. This paper describes the workflow to evaluate technical simulation methodologies of thermally active polymer technology for proper pilot project designs. The main challenges for predictability of such models, besides the modeling approaches depend on how the heterogeneity is incorporated to the model, dose model capture ILT/PLT data and how the channel and thief zone is incorporated into the model.

CORPORATE DATAFLOW: A CASE STUDY OF WOODSIDES SYSTEM DESIGN FOR TECHLOG Presented by J. Crosby (Woodside Energy Ltd, Australia)

Over the last two years, Woodside (an Australian Oil and Gas Exploration and Production company) has completed its evaluation, design, migration, roll out and optimisation of the Techlog Interactive Suite as a replacement for a competitors product. This case study examines some of the challenges faced along the way, and examines the chosen system design, particularly focussing on the implementation of Techlog Projects as a primary reference store for petrophysical interpretation in lieu of a more conventional, yet 3rd party database.

In migrating to Techlog, Woodside moved from having a reference and working database pairing for each project area, or basin, to having a single reference and multiple user projects for each basin we do not currently connect Techlog projects with a database solution such as Recall or OpenSpirit. We also moved from having multiple users in the one working database (along with all associated pros and cons) into having one project per user. Subsequently there has been significant effort required to optimise dataflows (the system by which data moves between projects and users) to facilitate ease and speed of access whilst maintaining data integrity. As Schlumberger harmonises its trinity of solutions under the Studio umbrella, dataflows are about to receive a lot of attention. Woodside hopes that the vision for Techlog Studio is one that will also benefit Techlog deployment in a corporate environment defined by users who simultaneously consider a wealth of wellbore data for ongoing field appraisal rather than catering primarily for production line operations where data is imported, processed and subsequently exported.

This presentation will look in finer detail at: the implementation and development of Woodsides Techlog solution; the challenges weve overcome deploying Techlog and managing data over our network; the introduction, implementation and limitations of the Techlog Synchronization tool and Reference Repository for our dataflows; and the preparation and planning being done for the future introduction of Studio for Techlog, and its perceived impact on the Woodside Techlog solution design.

THE DEPLOYMENT OF STUDIO IN AN ASSET TEAM; DATA MANAGEMENT IS THE KEY TO SUCCESS Presented by Dr Claire Andrews (Apache)

Studio is presented by Schlumberger as the solution to working in Petrel with in a high well count area and to increase collaboration within an asset team as well as being a core component to future links between other software such as OFM & Avocet.

The Case Study presented here is the deployment of Studio within an asset team actively drilling in North America to facilitate collaboration and efficient handling of data. During the course of the deployment many key lessons were learned regarding the necessity of data manipulation to preserve & create a matching GUID environment to enable the migration in to Studio. The changes in workflow & understanding of the data has become key to a successful deployment & has generated much discussion with Schlumberger on functionality required in the Studio DB environment. The project was successfully completed with minimum disruption to daily activities of the team with the second step commencing for end user training and the changes required in the workflow to use Studio. The further enhancement to the speed of Interpretation & Engineering workflows that connections with production systems and corporate data stores will allow is considered a key advantage of Studio & much anticipated.

NEW GENERATION ISOTHERMS DATASET FOR UNCONVENTIONAL RESERVE ESTIMATION Presented by M. D. Campos (Schlumberger)

Organic-rich shales and coals contain hydrocarbon fluids that are under strong influence of their pore walls due to the nanometric level pore-size distribution. At this scale, pore walls affect fluid phase transitions and its physicochemical properties, which in turn have an impact on current volumetric methods for calculating oil and gas reserve estimation in a typical unconventional field.

Isotherm tables currently used in the oil industry refer to the equation derived by Langmuir. Such isotherm represents fluid properties in which wall effects are not considered and single adsorption layers are assumed for any porous media. Hence, it fails to accurately represent the fluid properties and volumetrics for calculating the reserves of organic-rich shales and coal reservoirs.

New generation isotherm tables are therefore needed to take into account the added complexity in volumetric calculation for shale gas and shale oil estimation.

This presentation describes the methodology for which the new generation isotherm dataset has been created by utilizing molecular dynamics simulation results.

Use of the new isotherm will give an accurate result for volumes of gas in any shale type reservoir. The process of history matching will be reduced greatly as the results are more representative to field rates. A faster decision to report the volume of gas to partners, governmental bodies can be achieved thus creating confidence in the result.

MODELLING COMPLEX STRUCTURESVOLUME BASED MODELLING OPENS NEW PERSPECTIVES Presented by Thierry Modiano (Total E&P Nigeria)

Dealing with complex structures, industry has been for a long time waiting for robust techniques allowing obtaining precise structural models and reservoir grids while respecting the complexity of fault and horizon patterns. Building a geologically consistent representation of horizons when the fault network presents complex truncation has been a challenge for a long time, especially when horizons are represented by sparse data.

The new Volume Based Modeling (VBM) approach introduced in Petrel version 2013.2 is a global approach. Fault and horizon data are used to build an implicit function representing the geological time. This function is defined everywhere in the volume of interest. Horizons are simply iso-values of the implicit function.

VBM was used on a complex deep water field offshore Nigeria. In previous models, the structural complexity of the field obliged to split the model in three stratigraphic reservoir units and to proceed to many fault simplifications to remove internal truncations. Even with the simplifications, the process of grid building using the classical pillar gridding method was very long and many compromises were done to get an acceptable grid without distorting too much the fault geometry.

With VBM, the whole model without very few simplifications was successfully built in a very limited time, using the tops and bottom horizons of the three reservoir levels. A structural grid (full stairstep) was derived from this structural model.

A second structural model was built by adding internal horizons picked as tops and bases of sedimentary bodies. A second structural grid was built using this model. The objective of this detailed model was to get a structurally consistent representation of all sedimentary units. The zone property was then resampled in the first grid to obtain a discrete region property.

QUANTITATIVE INTERPRETATION IN THE PETREL PLATFORM Presented by M. Volcan (Schlumberger)

In many cases, inversion or AVO studies to predict reservoir parameters are carried out on data that has lost its context from the processing center. The analysis usually requires the use of multiple software packages to complete a full analysis. In this presentation, we will see how advantageous it is to perform data conditioning, inversion, and AVO workflows in one platform the Petrel platform to achieve an accurate subsurface characterization.

Technology to perform the inversion simultaneously allows the direct generation of the three rock propertiesAI, Vp/Vs and Densitywhich can help interpret the presence of fluids. This workflow highlights the practical aspects of quantitative interpretation in order to assist with prospect validation and reservoir characterization.

The Petrel platform is used to condition the data, and prestack is then used to evaluate and create deterministic and stochastic inversion results.

The ability to combine rock physics models with seismic is achieved by modeling the AVO response in our well to predict pore fluids in the seismic. The methodology to estimate lithology by using the acoustic impedance contrast is also showcased.

STRATEGIC TO OPERATIONAL INTEGRATED PLANNING Presented by Rick Lobrecht (Schlumberger)

Portfolio management is an important aspect of oil and gas business planning to support the efficient allocation of capital and other scarce resources. As oil and gas becomes more difficult and expensive to find and extract, petroleum companies are looking to portfolio management for competitive advantage. However, traditional portfolio management has sometimes missed the opportunity to consider the operational reality at the asset team or regional level. Each investment must be consistently evaluated for its ability to contribute to the corporate strategy, while maximizing the usage of available resources.

This talk will show how integrating strategic and operational planning provides benefits when used at every stage in the asset development life cycle (from exploration through to production and abandonment) as well as at different levels in the corporation (asset teams through business units to corporate planning) to drive efficient business planning. It will focus on what the critical business issues are, how to model the corporate long-term direction through measurable goals and key performance indicators, and what key objectives companies pursue when allocating and budgeting capital.

The presentation will highlight specific examples of ways in which portfolio management can resolve operational issues, such as rig-scheduling optimization, facility constraints, and asset performance monitoring, while maintaining the golden thread connection to the long-term strategy.

This integrated approach to portfolio management will allow corporate and asset planners to balance long term strategic goals with operational constraints from the business unit down to the asset team. It results in a more balanced and diversified portfolioan achievable planand drives better decisions in the capital allocation process.

MODERNIZING OIL & GAS SOFTWARE: HOW INTEL AND SCHLUMBERGER INCREASED PIPESIM PERFORMANCE 10X Presented by Joseph Curley (Intel)

By working together to parallelize Schlumbergers PIPESIM Steady-State Multiphase Flow Simulator, Intel and Schlumberger enable oil and gas companies to explore many more pipeline production operation scenarios by capitalizing on the latest multi-core processing architectures to run simulations faster, with greater accuracy, and explore more design alternatives.

ASSESSING THE IMPACT OF EOR IN YOUR RESERVOIR Presented by Omer Gurpinar (Schlumberger)

This is the most exciting time for EOR in recent memory. At last, almost everyone is talking about increasing recovery factors, and IOR/EOR is being considered a natural component of reservoir management. Furthermore, many traditional philosophies are being openly challenged. EOR planning is happening as part of field development plans. Proven technologies are being adapted in new, smart ways and new technologies are constantly evolving from research to commercial applications, making successful EOR projects more likely.

These new directions are the result of a variety of factors. Most fields, including the giant ones, are maturing, and producing liquid hydrocarbons is getting tougher in all kind of reservoir types (conventional and unconventional alike). Leaving about 65% of the in-place reserves left unrecovered has been challenged.

There have been developments on many fronts (i.e., advanced reservoir characterization, multiphase flow physics, smart well and intelligent completions, advancements in recovery research, monitoring and control technologies, new EOR chemicals, new EOR pilot concepts, and new observation-well concepts). The collective impact of these is going to make new EOR projects more successful than before.

Increasing recovery factors has been considered as a fully integrated multidomain activity (from pore space to separator, and everything in between). Severe production decline in tight-light (unconventional oil reservoirs) reservoirs is also making the industry think about recovery challenges.

EOR has been brought into field development planning in most recent offshore oil developments, and the integrator media, reservoir modeling, is now ready to tackle the recovery challenge.

Broadening the scope of recovery challenge to all domains will make realizations of new reserves more likely, but this change will bring additional challenges. Modeling for EOR is no longer limited to investigation of mobilizing the trapped oil, but incorporation of all scales, from pore-scale (sometimes molecule scale) to reservoir scale, including the performance of exotic EOR pilots with monitoring sensors and controls.

Geomechanics, which came to our industry first for the drilling domain, will have to be part of EOR modeling in reservoir scale. Additionally, new EOR schemessuch as loSAL, hybrid applications (VAPEX), and new conformance ideas including foams and nanoparticleswill push us to better understand the recovery thermodynamics, physics, and multiphase flow in porous media.

Evolution in recovery phenomena will guide us to set the right granularity in reservoir and fluid characterization, which will in turn enhance the capabilities of reservoir models. If we continually push the science, an opportunity to double recovery factors exists.

A ROADMAP TO ASSET OPTIMIZATION: THE PRODUCTION DATA MANAGEMENT PLATFORM Presented by T. Tran (Bien Dong Petroleum Operating Company)

Bien Dong POC operates the Hai Thach and Moc Tinh gas/condensate fields located offshore Vietnam and exports the produced gas to the Nam Con Son Pipeline. Bien Dong POC has decided upon the Schlumberger Information Solutions (SIS) Avocet Platform technology that encompasses functionality designed to collect, manage and compute production data in high and low frequency, produce meaningful reports supporting the analysis and enhancement of the operational activity. With this data converted into information Bien Dong POC can safely operate the current and future oil and gas assets, accurately report to authorities and stakeholders, perform asset surveillance, diagnosis and ultimately optimize production amid operational constraints.

In order to obtain the most of this solution, the Avocet Platform project was implemented before the first commercial gas, allowing them to be readily prepared for first gas, enjoy the benefits of tracking all the production and operation parameters since day one for operational purposes and also enabling the ability to understand better the reservoir dynamics at very early stage of the production.

As Avocet provides foundation layer for managing the production for the two fields, and is helping today to improve the timely decision making process through the use of accurate, and validated data; this effect is impacting positively by allowing Bien Dong POC to adjust production rates to deliver contractual terms of demanded production in a matter of few hours.

The goal of this paper is to highlight the advantages and benefits that can be drawn from the utilization of the Avocet Platform Solution as key foundation block today and how it fits in the Roadmap to Asset Optimization in the future for Bien Dong POC.

THE USE OF A VOLUME BASED MODEL WORKFLOW TO RESOLVE THE COMPLEX ARCHITECTURE OF A FIELD ON THE NORTH WEST SHELF, AUSTRALIA Presented by A. Kaiko (Woodside)

Until recently the complex fault architecture of the North Rankin Field was not able to be modelled, using standard pillar gridding techniques, without significantly over simplifying the faulting pattern of the field. In order to better understand the dynamic performance of the field it is important that the complex fault architectures be captured. The use of the Structural Framework workflow with the release of the Volume Based Modelling (VBM) algorithm and Stair Step Gridding, has enabled the complex architecture of the North Rankin Field to be modelled and a more representative grid generated. This grid is now able to be used in the dynamic realm to help provide a better understanding of the potential aquifer influx, pressure baffling and production history of the field.

The fault styles within the North Rankin Field include top truncation, multiple stacked antithetic and crossing faults. From a range of varying data inputs, the use of VBM is able to generate horizons honouring the complex fault architecture and stratigraphic trends even in areas of little well control. The seismic inputs for the model consist of the complex fault set and three key highly detailed input horizons to give the overall framework. A secondary set of four more sparsely interpreted horizons were also used to provided further infill to the model. Well tops and occasional seismic infill picks in complex areas provide the final input to complete the complex framework build. A stair step grid is then generated which was populated with the various properties to be used for dynamic assessment of the field performance.

The use of the VBM workflow and a tiered seismic interpretation approach allows a new level of structural complexity to be modelled, while minimizing the seismic interpretation required.

TECHNIQUES FOR EXPLORATION AND EVALUATION OF TURBIDITES Presented by A. Acevedo (Schlumberger)

Over the last decade, there have been several discoveries of very significant oil accumulations in deepwater reservoirs. With advances in research and the availability of high-resolution seismic data, their variability and complexity have been well documented. For hydrocarbon exploitation purposes, however, the industry has been lacking an integrated approach to interpret these reservoirs using multiple domains and data efficiently. This presentation describes a series of innovative and interrelated techniques to improve the understanding of these types of reservoir at three scales: basin, sequence, and reservoir. The combination of multiple disciplines (such as geophysics, stratigraphic forward modeling, and geostatistics) at these three levels leads to a more realistic representation of these plays.

CREATING ADVANTAGE THROUGH EXTENSIBILITY WITH THE OCEAN FRAMEWORK Presented by Ahmed Aqrawi (Schlumberger)

The Ocean software development framework gives you the freedom to create advantage. By building or integrating specialized applications and workflows inside the Schlumberger software platforms, you can leverage your own proprietary technology and ideas, and immediately put innovation into the hands of geoscientists. These capabilities can be developed internally or by working with Ocean partners to rapidly incorporate new science into your workflows.

In this presentation, discover how you can make use of best-in-class technology without the disadvantages and inconvenience of multiple fragmented software solutions. Extend your Schlumberger technologies with the unique Ocean framework and choose tools that meet your needs from Schlumberger and third parties via the Ocean store.

FLAIR, ISOTOPE, ACC: THE ROLE OF THE SURFACE CONTINUOUS FORMATION EVALUATION Presented by Isaac Easow (Schlumberger)

In the last few years, advanced surface technology has gained fast popularity among several oil companies as trusted and valuable tools for formation evaluation. The quasi real-time availability makes these technologies suitable for quantitative and repeatable rock and fluid evaluation prior to subsurface logging or downhole fluid sampling runs.

FLAIR fluid logging and analysis in real time, Real-Time Isotope logging and ACC (Advanced Cutting Characterization) services represent a unique and complete formation evaluation portfolio in the mudlogging market. The FLAIR service continuously analyzes hydrocarbons extracted from drilling mud returns at surface, providing C1C5 composition analogous to the downhole reservoir fluid. The increased number of data available for analysis and the need to integrate all of them in a unique platform has led GSS to choose the Techlog wellbore software platform. The powerful functionalities of this software meet perfectly the requirements for an advanced formation evaluation analysis.

This presentation focuses on a US shale gas play, where elemental composition of the cuttings showed great potential for chemo-steering and production allocation.

COST-EFFICIENT SOLUTIONS FOR SIMULATING INTEGRATED RESERVOIR MODELS AND PRODUCTION NETWORKS USING INTERSECT AND A FAST NETWORK SOLVER Presented by C. Casciano (Eni)

It is a well-known fact that, in many cases, predicting and optimizing field production involves the simulation of different reservoirs sharing a common production network. Various solution have been proposed, ranging from a combination of simple Network and Reservoir Coupling options in black-oil simulators like ECLIPSE 100 to more elaborate solutions where a controller application drives reservoir models and a fully-fledged network simulator/optimizer. If the latter option is more accurate, the former solution is often much more efficient and gives similar results.

In this presentation we describe, within the INTERSECT simulation framework, a pre-commercial but effective work-flow aimed at integrating independent reservoir models and a common production Network.

In this solution, INTERSECT Field Manager integrates in an iteratively lagged manner a fast network solver, where pressure drops along flow lines are computed using VFP tables, with INTERSECT models simulating fluid flow from reservoir to well-head.

The methodology is first described and then highlighted by means of some key real field applications. Advantages with respect to more elaborate solutions are also discussed.

ASSET OPTIMIZATION AND RESERVOIR/PETROLEUM ENGINEERING DATA MANAGEMENT Presented by E. Kabadayi (ConocoPhillips)

The ultimate goal for this project was to set up a foundational data access for reservoir/production engineers to run variety of engineering, analytical and visualization applications. Building a gas lift management system to monitor and optimize the Greater Ekofisk assets as well as building alarm systems and other engineering applications and workflow optimizations were planned as later phases of the initial project. Ekofisk is one of the biggest and oldest assets in Norwegian continental shelf having some 200 wells, waterflooded, and majority of wells are gaslifted. To add to the complexity of the asset, some of the wells are 40 year old and not much of instrumentation while some others are fairly advanced and highly instrumented. As a known challenge for this type of brown fields there are many data sources, sometimes several places to look for the same data. The aim was to generate a single system intelligence based on the Avocet platform including all the engineering data types built across multiple data sources, automatically pulling in data with the right frequency, QCing it, and connecting to BI or engineering analysis tools. The commercial data sources are PI (daily/hourly operational data such as pressure, temperature, and flowrate readings), EC (daily/monthly allocated volumes), WellView (static well data such as completion details), and OpenWorks (static well ID and location data). The custom-built data sources are a couple of Oracle/MS Access based databases containing reservoir parameters, well tests, ion tracers, etc.

This system is now connected to engineering analysis tools such as OFM, business intelligence tools such as Spotfire and the Petrel to perform reservoir engineering workflows. The next step is to build optimization workflows on the top of the system and at the moment CoP Norway is evaluating options in this regard.

DYNAMIC FLOW MODELINGCRITICAL TOOLS IN RISK MANAGEMENT FOR WELL CONTROL Presented by Fred Ng (Wild Well Control, Inc.)

Recent events have heightened awareness from industry and governmental authorities regarding well control issues and consequences. Management of these risks involves development of mitigation and contingency options for identified risks. This paper discusses the critical role of dynamic flow modeling in developing such options, as well as the important differences resulting from application of advanced technologies in recent years. These include multiphase modeling to address well plan and kick tolerance evaluation for mitigation options, as well as relief well planning and simulation of blowouts and dynamic kill for contingency planning. Advanced applications, such as those involved in SIS well control software, allow complete and accurate modeling of the physical effects, which are typically not feasible with the oversimplified models used by others. Case histories will be presented to illustrate these effects, which include mud compressibility, gas solubility in oil based fluids, PVT effects of multiphase influx, migration of gas in the wellbore, temperature effects, unloading of the well in developing a blowout, and mud / gas swapping in the wellbore. Discussions will also include changes needed to meet new developments in drilling operations.

THE HYDROCARBON PATHWAYINTEGRATED DRILLING SOLUTIONS Presented by Stuart Jardine (Schlumberger)

Drilling is an integral part and a key component of the hydrocarbon pathway. Meeting the objective of your well is a critical activity in each of the lifecycle stages and with increasing well complexity, getting it right the first time has never been more important.

This presentation covers key workflows throughout the drilling lifecycle, from planning through engineering, execution, and evaluation of the completed drilling program. The drilling workflows highlight well planning in a geological context, workflow integration, and unique technologies for todays high-value complex wells.

Well trajectory design is implemented using efficient iterations between the geologist and drilling engineer. The initial design is optimized for the drilling pressure window and includes a review of the potential wellbore stability issues that may lead to drilling problems. With the well trajectory finalized and the safe operating window calculated, we use dynamic hydraulic models including dynamic temperature calculationsto ensure that the bottomhole pressures in the well can be maintained within this window. The focus on well control highlights a new solution to simplify relief well and blowout contingency planning utilizing advanced multiphase hydraulics simulation capabilities.

Real-time data services, combined with drilling performance analysis capabilities, complete the drilling lifecycle. All relevant well information is immediately available to feed into the plan and offset analysis for the next well to be drilled.

FRACTURE INTERPRETATION AND MODELING Presented by J. Klinger (Schlumberger)

Having a confident understanding of the fracture orientation, distribution, and characteristics is crucial in a general context where 80% of the worlds largest hydrocarbon bearing fields are fractured reservoirs. The methodology proposed here will combine a deterministic geomechanical inversion through a boundary element method engine (BEM), with the reservoirs structural interpretation (cf. fault framework) and estimate the locally perturbed paleostress-field in order to describe the natural fractures generated by a given tectonic event. Calibration to the fractures interpreted at the wellbore will ensure we have reached the global minimum of the inversion step.

Subsequently, information of the present-day stress field within the reservoir (obtained via similar inversion workflow using break-out information to calibrate against, or other means) will be used in order to compute a fracture reactivation potential property. Such information can be highly valuable for well, completion, and stimulation planning protocols.

MAKING KNOWLEDGE WORK IN THE WELLBORESTUDIO FOR TECHLOG Presented by P. Dineen (Schlumberger)

With the pace of change in our industry todayand the increasing effort on exploring, developing, and producing challenging reservoirs in both conventional and unconventional environmentsthere is significant focus on user and team productivity in an E&P organizations quest for optimization of workflows across the lifecycle of the asset.

The Studio E&P knowledge environment addresses these challenges by delivering a new level of collaboration across multiple assets and multiple domains to support your teams along the hydrocarbon pathway. The Studio environment focuses on empowering end users, both petrotechnical users and data managers, with a powerful platform for collaboration with utilities, tools, and workflows that enable them to access, review, capture and share critical knowledge and insight as part of their technical analysis and decisions, all delivered as part of the Schlumberger platforms, as well as a dedicated Studio Manager to proactively oversee and administer the Studio environment.

This presentation will share the advances made around the Techlog platform and integration into the Studio ecosystem for collaboration and knowledge management.

We will review the core workflows delivered with Techlog 2014 and Studio 2014 that deliver a step change in the collaboration between Techlog users and across the asset with the Petrel platform, enabling your teams to increase productivity and collaboration to improve insight and decisions in the dynamic environment they are working in.

A SAFE HARBOR FOR DATA IN THE OCEAN ENVIRONMENT Presented by J. Whelan (ExxonMobil)

The management of data is a fundamental component of ExxonMobils system of management controls. In 2003 ExxonMobil began deploying Petrel as a generalist geoscience interpretation tool. Though the benefits of integration were clear, it soon became apparent that without a database, it would be difficult to deploy Petrel as an enterprise solution, while adhering to our Data Management Principles. Projects replicated, data was duplicated, disk usage grew and data integrity became questionable. Identity management also became an issue making collaboration difficult. This talk will discuss our journey down the road to Petrel Studio Knowledge and will cover both the challenges and benefits achieved through early implementation of the Petrel Database.

DETERMINATION OF PERFORMANCE PARAMETERS OF A PROSPECTED GAS STORAGE RESERVOIR UNDER UNCERTAINTY Presented by Alexander Gubik (RAG)

Reservoir management workflows are increasingly built on reservoir simulation support for optimizing production schemes and estimating the impact of subsurface uncertainties on field development scenarios. Reservoir simulation models are calibrated to geological data and accurate reproduction of historical production data. These are defined as a prerequisite for reliable production and performance forecasts. The solution space for a history match is in some cases very big and a deterministic approach represents only one possible solution, not accounting for any uncertainty. In this work we describe a workflow design for the determination of turnover and cushion gas volume of a prospected gas storage reservoir under uncertainty. The following challenges are addressed; define and reduce uncertainty in calculated working gas volume and cushion gas requirements, improve understanding and control over operating economics, optimize operating efficiency to maintain competitive advantage. The following solutions are chosen and combined in an efficient workflow design:

Generation of hundreds of alternative realizations of the original geological model, using the Petrel platform Selection of detailed models generated in the ECLIPSE simulator and comparison to production history, giving 100 well-matched alternatives Uncertainty quantification using MEPO software and optimization of key performance indicators like working gas volume, cushion gas volume and storage well performance.

Presented results are based on multiple-realization workflows. Deployment strategies and efficient use of HPC resources are briefly discussed for uncertainty quantification and optimization workflows.

SHALLOW GAS EFFECTS ON SEISMIC AND CORRECTION METHODS Presented by Rizal Bakar (Petronas)

In peninsula Malaysia, shallow gas effect is commonly observed due to the gas attenuate the acoustic energy, areas with high gas content will be deflected downward or called pull downs effect cause by reduction of speed of acoustic.

In the past, most of the correction was done manually by estimating the pull down effect base on geological understanding of the area; however the uncertainty of this method was very high as is not fully supported by the data of that area, hence affecting the hydrocarbon volumetric uncertainties.

Since this is a common issue, it is essential for Petronas to establish the standards workflow with the objective is to have a standard guideline for shallow gas seismic correction to affected fields. To ascertain the workflow, a lot of data gathering and analysis has been done to really understand the issue and the volumetric uncertainty from the pull down effect. Data involved in this study are seismic data such as PSTM, PSDM and 2D OBC , Velocity data such as VRMS and staking velocity , Well data such as Sonic log, Density log, VSP, Check shot and previous interpreted horizons in time and depth.

Table below is the summary of the workflow established using Petrel Software involves data preparation followed by Interpretation and analysis before doing the shallow correction and domain conversion from time to depth.

The challenges of shallow seismic correction is the appropriate and sufficient data availability and if necessary may require new seismic processing or even need to re-acquire new seismic data as long as if it is supported by the economic justification.

PERSPECTIVES ON THE PETROTECHNICAL CLOUD Presented by Vasu Guruswarmy (Schlumberger)

Now more than ever, the winds of change in the world of information technology are felt in the world of upstream exploration and production. The looming presence of the cloud is raising many questions: What might be its value to my organization? How can I practically apply the cloud to the challenges faced by my organization?

To make sense of the cloud, we are encouraged by enterprise and consumer IT providers to view the landscape along four axes: cloud, big data, devices, and social. To understand the implications and opportunities for our industry of this change, we must add to this list of megatrends. We must include two additional dimensions that often take a back seat in a cloud conversation. The first is security, recognizing the importance of our industry to the world, both politically and economically. The second is remote access, due to the geographical spread of upstream exploration and production enterprises.

This talk will explore the scope for cloud technologies in our industry, specifically desktop virtualization and high-performance computingthe two critical elements used in modern decision-making. It will equip you with the questions to ask yourself and your suppliers as you seek to understand where and how the cloud paradigm can add value to your business.

COMPRENHENSIVE REAL-TIME DRILLING MONITORING METHODOLOGY DEPLOYED BY PEMEX TO REDUCE DRILLING RISKS IN HIGH PRESSURE ZONE Presented by R. Hernandez (PEMEX)

The Kuil field operated by PEMEX is located in the Gulf of Mexico and represents a key source of current hydrocarbons production and an important potential to increase Mexicos reserves. Nevertheless, drilling across the Kuil field has represented major challenges for the operator and service companies. Technical studies of the field helped identify that drilling issues like stuck pipe, high torque, and loss circulation have occurred due to poor hole cleaning practices and incorrect mud density selection in the high pressure zones. In order to identify, prevent, and mitigate the occurrence of the mentioned drilling events, PEMEX deployed inside its regional REAL-TIME operations center COIP (Centro de Operaciones Integrales de Perforacin), a multi-disciplinary team of Schlumberger specialists to apply innovative REAL-TIME drilling monitoring methodologies. These methodologies integrate specialists from five areas of expertise (drilling, geomechan- ics, geophysics, geology and petrophysics) working together by combining subsurface models with surface and downhole tools data within advanced technology platforms like Petrel, Techlog and PTK. The COIP team has made excellent contributions to the safe and efficient well construction process in the Kuil field; here are some of the highlights:

Effective reduction of non-production-time events and consequently decrease of total costs. Figure 1 shows the significant reduction in total times in the 12 section after deployment of the COIPs team by PEMEX.

Major Improvements on the fields Mechanical Earth Model resulting in more reliable and accurate mud weight selections to avoid well control incidents in abnormally pressured zones

Deployment of enhanced multi-domain procedures to deal with potential drilling events related to existing geological features like faulted zones and challenging mechanical rock conditions

The multi-discipline integration that makes up the COIP team in conjunction with the superior technology platforms and advanced workflows, has proven to provide an effective solution that guarantees proper drilling risk management and optimization in the PEMEX Kuil field.

MODERN FORMATION EVALUATION FOR APPRAISAL WELLS Presented by B. Moss (Schlumberger)

Appraisal wells are designed to capture the maximum amount of information about the reservoir and its overburden, in order to derive the most comprehensive understanding possible about the extent and quality of the reservoir rocks and how they are likely to best produce their hydrocarbon.

In this review paper, we take a snapshot of the state-of-the-art in static formation evaluation that has been reached by todays well-based logging and coring technology. The paper takes a thematic approach and briefly covers the principal target formation attributeslithology (geology), porosity, permeability, saturation, pressures, and geomechanicsand provides examples of the way in which modern tools and techniques have extended the detail of what we can learn today about these important facets of formation evaluation.

THE EFFECT OF GLACIATIONS ON PETROLEUM SYSTEMS IN THE NORWEGIAN BARENTS SEA Presented by Jesper Kresten Nielsen (North Energy)

One of the most significant challenges facing petroleum exploration in the Norwegian Barents Sea (and other regions in the Arctic) relates to the severe erosion and uplift that occurred during Plio-Pleistocene ice age (de-)glaciations. The seabed of the Barents Sea was strongly eroded during these ice ages, with several hundred metres of sediments removed. Such a glacial influence has often been regarded as the major risk for the retention of already entrapped oil and gas, potentially initiating or reactivating faults and other fractures, as well as spilling and leaking oil and gas reservoirs observed as pockmarks and gas chimneys. This may also involve a decreased depth of hydrocarbon kitchens and tilting of migration routes. To explore the influence of ice ages on petroleum systems, we have integrated both the ice and the associated erosion in PetroMod 3D models in order to mimic the resulting temperature and pressure changes relatively deep within the shelf.

The integration of ice sheets in the PetroMod 3D models affects both sediment thermal conductivity and surface temperatures. The duration of a typical glacial period (with a relatively short inter-glacial period) is sufficient to establish a steeper temperature gradient, which can result in reduced reservoir temperatures. Depending on the scenario, the choice of whether to model a wet-based ice sheet or one with frozen pore water at its base has a critical impact on the depth to which the temperature change reaches.

Ice sheets lying on the exploitable sedimentary succession introduce increased loading and thereby raised pressure in the subsurface. The melting of this ice then results in shelf rebound and loss of pressure. Such geologically rapid fluctuations in both temperature and pressure controlled by dynamic ice thicknesses and associated properties may result in repeated gaseous-liquid phase transformations in petroleum reservoirs.

PEARLPROJECT MATURATION MANAGEMENT Presented by Rosli Rahim (Petronas)

PEARL is based on the projects-resources-reserves model deployed in PETRONAS and therefore is designed from the ground up to support core petroleum engineering activities in PCSB. It comprises the Project Maturation Management sub-system and the Resources and Reserves Management sub-system. The current phase covers Project Maturation system which captures birth of a project up to project execution or Final Investment Decision(FID) stage. The geoscience, reservoir engineers and drilling teams, and planners work on the same project but within their domains. This is also a platform for the review processes like the line department reviews and host government reviews. In addition, this system serves as a source for planning activities.

How can this knowledge be used? This knowledge would be greatly useful for projects dealing with business processes and approvals.

Who can use this knowledge? What role? Consultants, project manager, engineers.

When can this knowledge be used? Which stage, what environment, which context? This knowledge can be applied in an environment that involves multiple disciplines working simultaneously in different systems contributing to one process or the same objective.

Expected Benefits of using this knowledge Some of the benefits include: Connects various disciplines involved in the same business process Captures data at the source dynamically and intrinsically throughout the workflow Improves work productivity significantly Promotes data integrity, ownership and accountability Enables reviews and decision making by giving access to the latest state of information Aligns business processes that derive information from the same source

What pain does this knowledge cure? Addresses the following challenges: No centralized platform for identifying project status Rework of same data for various business exercises Lack of data accountability Misalignment of data between business exercises Key Success Factors for using this knowledge Solid understanding of the business workflows including the what, how and when data flows between systems and departments.

TIE-BACKS IN MATURE AREASTRANSIENT SIMULATIONS IN FEASIBILITY STUDIES Jan Gunnar Waalmann (Aker Solutions)

Field development in mature areas presents specific challenges. Keywords for these developments are fast track, low cost, standardized solutions. Small satellite fields require host facilities in order to be economic. At the same time the aging hosts tend to need additional production in order to be economic. With hosts coming close to design life, the time window for development of new reserves in the mature areas is limited. When operational cost exceeds the income, fields will be shut down. Shutting down fields will impact the life of the infrastructure of the area.

In a time with subsea developments going down towards water depths of 3000m, and subsea compression becoming a reality, designing a tie-back to an existing installation sounds like an easy task. However, many challenges tend to materialize on the way. With the usual weight and area challenges, typical keywords are limited riser and umbilical hang-off capacity, limited topside slug and liquid handling capacity, limited power generation capacity, limited inhibitor (MEG/MeOH) storage capacity, limited inhibitor pump capacity, limited flare capacity, limited design pressures etc.

This means that transient thermohydraulic multiphase flow simulations are required already at feasibility study level. Even though internal procedures and guidelines in the operating companies usually only demand steady state evaluations at this level, feasibility can only be substantiated through transient simulations. Is it possible to design a system with a sufficiently robust flow assurance strategy and margins?

Evaluations that must be done may include cooldown simulations, evaluation of slug mitigation by means of gas lift or similar, flowline blowdown simulations, inhibitor tracking for planned flowline pre-inhibiting, start-up after unplanned shut-down, potentially HIPPS evaluations etc.

The presentation will use examples from recently executed projects to illustrate use of OLGA as an integrated tool in the field architecture selection and design process.

MAXIMIZING BUSINESS VALUE THROUGH OPTIMAL PETREL UPTAKE Presented by B. Ragosa (ExxonMobil)

ExxonMobil has been deploying Petrel to its global Upstream companies for the past decade. During this period we have learned several lessons that have allowed us to maximize business value while supporting a rapidly evolving Technology system.

The presentation will include an overview of ExxonMobils global approach to Geoscience technology management, including processes for coordinating software, hardware, data, and support. We will document lessons learned from multiple Petrel deployments and the next steps we are taking to optimize our Petrel investments.

INTEGRATED APPROACH TO WELL INTEGRITY DECISIONS IN TECHLOGCONSTRUCTION, PRODUCTION, AND ABANDONMENT Presented by Ram Sunder Kalyanraman (Schlumberger)

The focus on environmental safety during the life of the well (i.e., from well construction to production and abandonment) has clearly increased over recent years. There is a growing need for comprehensive well integrity interpretation procedures that require integrating information and interpretations. This leads to well-informed decisions that not only improv